Utilization of reformer make gas



Dec. 18, 1962 w. H. DAVIS UTILIZATION OF REFORMER MAKE-GAS Filed July17. 1959 3 Sheets-Sheet 5 3 TO REF|NERY FUEL MAiN TO c ac RECOVERY 2nREFORMER RECYCLE BEXCESS uoum GAS

SEPARATORZ I87 25 2I4 SREFORMATE REFORMER CASCADE GAS PRETREATERREFINERY T0 0 v RECOVERY D E 5 w 0 9303 E m F R E M R o F E R 6 5 m E EF m B T 5 A 2 E m m E c 2 R all z p G 3 .la mm F.

AGENT.

The present invention rel ates to hydrodccontamination of petroleumfractions boiling above the boiling range of reformer feed, i.e.,boiling above about 350 to about 420 F. and the hydrodecontarnination ofreformer feed employing hydrogen-containing gas produced in a reformingunit and, more particularly, to the hydrodecontamination of highnitrogen content reformer feed stocks in conjunction with thehydrodecontamination of a Detroleum fraction boiling above the boilingrange of reformer feed, i.e., boiling above about 350 to about 420 F.

Hydrodecontamination as used herein is the treatment of a mixture ofhydrocarbons containing compounds of sulfur and/or nitrogen in thepresence of hydrogen with a particle-form solid catalytic materialhaving hydrogenatingas Well as hydrodesulfurizing and/orhydrodenitrogenizing capabilities. In the hydrodecontamination ofpetroleum fractions boiling above the boiling range of reformer feed,i.e., boiling above about 350 to about 420 P. such as domestic heatingoil, the treatment produces a domestic heating oil stable to at leastone of color and sediment and containing not more than about 1 to 2percent of sulfur (total sulfur) and not more than about 1 to 2 percentof mercaptan sulfur [RSH(S)] originally present in the untreateddomestic heating oil. In the hydrodecontamination of reformer feed thetreatment produces a reformer feed having a sulfur content the corrosiveeffect of which is within practical limits and a nitrogen content havinga deactivating effect upon platinum-group reformer catalyst withinpractical limits. W on the reformer feed is to be reformed over aplatinumgroup cataiyst, e.g., a particle-form platinum-group catalystcomprising about 0.1 to about 2.0, preferably about 0.35 to about 0.6,percent by weight platinum, about 0.35 to about 0.8 percent by weightchlorine on an alumina support, the maximum nitrogen content of thereformer feed is about 1 ppm.

A high nitrogen naphtha, i.e., a naphtha having a high nitrogen contentor a high nitrogen content naphtha, is a naphtha containing an amount ofnitrogen in excess of that which can be reduced to not more than 1 partper million (ppm) of nitrogen when treating the aforesaid high nitrogennaphtha alone or blended with a low nitrogen naphtha in existingreformer feed preparation facilitree.

A low nitrogen naphtha, i.e., a naphtha having a low nitrogen content ora low nitrogen content naphtha, is a naphtha the nitrogen content ofwhich can be reduced to not more than 1 ppm. in existinr. reformer feedpreparation facilities.

The stabilization of domestic fuel oil with respect to color andsediment has been a problem of increasing importance as the proportionof cracked stocks in the finished blend increased. One f the mosteffective means for producing a domestic fuel oil stable at least withrespect to color after storage is hydrogenation of the domestic fuel oilin contact with a catalyst having hydrodesulfurizing and hydrogenatingcapabilities. Among the catalysts having the aforesaid combinecapabilities are those comprising a mixture of the oxides of cobalt andmolybdenum. The hydrodecontamination of petroleum fracfigns bailingabove the boiling range of reformer feed, i.e., boiling above about 350to about 420 F. by hydrogenation in the presence of a catalyscomill'ising a mixture of the oxides of cobalt and molybdenum on hiredStates Fa -tent @i Patented if ec. 18, 1962 the alumina is accomplishedby contacting the aforesaid petroleum fraction under the followingconditions:

Catalyst: About 1.5 to about 3.8 percent by Weight of an oxide ofcobalt, about 7.0 to about 16.0 percent by weight of an oxide ofmolybdenum on alumina as a support.

With the increased demand for gasolines having octane ratings higherthan it has become necessary to reform gasolines, such as thermalgasolines, which until recently met customer demand without reforming.Many of these gasolines have nitrogen contents in excess of that whichcan be reduced, alone or blended with low nitroge aphtha, to not morethan 1 ppm. in existing reformer feed preparation facilities. On theother hand, it has been found that when reforming naphthas over aplatinumtype reforming catalyst the nitrogen content of the chargenaphtha must not be in excess of 1 ppm.

it is also conventional to hydrodesulfurize straight run naphthas andother low nitrogen naphthas prior to reforming in order to reducecorrosion of the heaters, piping and reforming reactors.

All of the foregoing hydrodecontaminating reactions require hydrogen.Yet, generally, the only source of hydrogen in a refinery is thatproduced in reforming.

Thus, the refiner is confronted with the problem of providing hydrogen(1) for the treatment of petroleum fractions boiling above the boilingrange of reformer feed, i.e., above about 350 to about 420 F. forexample, of raw domestic heating oil stocks, (2) for thehydrodecontamination of high nitrogen content gasoline stocks to bereformed, and (3) for the hydrodesulfurization of low nitrogen naphthato be reformed.

it has been found that the hydrogen-containing gas produced in areforming unit can be used to hydrodecontaminate the reformer feed in apretreater and the hydrogen containing gas from the pretreater can beused to hydrodecontaminate a petroleum fraction boiling above theboiling range of reformer feed, i.e., above about 350 to about 420 P.such as domestic heating oil, kerosine, gas oil and the like to providea more stable domestic heating oil or kerosine and a gas oil having areduced sediment content and of reduced sulfur and/or nitrogen contentin a hydrotreater or refiner. When the pressure in the reforming unit issnficiently higher than that in the pretreater and the pressure in thehydrotreater treating the petroleum fraction boiling above the boilingrange of reformer feed is sufficiently lower than that in the pretreaterand the amount of hydrogen circulated in the hydrotreater is not greaterthan the excess hydrogen produced in the reforming unit the excesshydrogen can flow from the reforming unit through the pretreating unitand through the hydrotreating or refining unit without recompressionintermedite to the reformer recycle gas compressor and the pretreatingunit and without compression intermediate the pretreatin unit and to thehydrotreating or refining unit. Thus, when the pressure drop between thereformer recycle compressor and the pretreating reactor or pretreater isof the order of about 30 pounds per square inch or more and the pressuredrop between the pretreating unit liquid-gas separator and thehydrotreating or refining unit reactor or hydrotreater is of the orderof about 30 pounds per square inch or more the reformer gas in excess ofthat required in the reformer, i.e.,

the excess reformer gas, can be cascaded from the reformer through thepretreating unit to and through the hydrotreating or refining unit.However, when the pretreater and/ or the hydrotreater is or are operatedat higher pressures than that of the reformer it is necessary torecompress the excess reformer gas between the reformer and thepretreater and between the pretreater absorber and the hydrotreater.

With certain reformer feeds under various reforming conditions theamount of excess reformer gas produced is less than the quantity ofhydrogen required for circulation in the pretreating unit and/ or thehydrotreating or refining unit. Under these conditions a portion of thecirculating hydrogen-containing gas in the pretreating unit and/ or thehydrotreating unit is recycled. The amount of circulating gas recycledin the pretreating unit and/ or the hydrotreating unit is the amount ofcirculating gas required less the amount of available excess reformergas. Thus, with a reformer producing 1000 s.c.f. of hydrogen and thepretreater requiring 2000 s.c.f. of hydrogen per barrel about 1000s.c.f. of hydrogen from the liquid gas separator in the pretreating unitis recycled through the pretreating reactor system together with about1000 s.c.f. of hydrogen as excess reformer gas. Similarly, when thehydrogen circulation rate in the hydrotreater or refiner is 2000s.c.f./bbl. of refiner feed and the excess reformer hydrogen is 1000s.c.f./bbl. of refiner feed, 1000 s.c.f. of hydrogen per barrel ofrefiner feed is recycled together with 1000 s.c.f. of hydrogen perbarrel of refiner feed secured from the reformer or the absorber of thepretreater.

Accordingly, it is an obiect of the present inveniton to provide a meansfor hydrodecontaminating a petroleum fraction boiling above the boilingrange of reformer feed, i.e., boiling above about 350 F. to about 420 F,e.g., kerosine, domestic heating oil, gas oil and the like to produce atreated petroleum fraction boiling above the boiling range of reformerfeed, i.e., boiling above about 350 to about 420 F. having a reducedsulfur and/or nitrogen content whilst hydrodecontaminating a reformerfeed usually having a maximum boiling point in the range of about 350 toabout 420 F. to obtain a treated reformer feed containing not more thanabout 1 p.p.m. of nitrogen, and to reform the treated reformer feed inthe presence of hydrogen and particle-form solid platinum-groupreforming catalyst under reforming conditions of temperature andpressure to produce a reformate of improved octane rating and hyrogen-containing gas wherein the aforesaid hydrogen-containing gas,hereinafter designated excess reformer gas, is used in thehydrodecontamination of the aforesaid reformer feed and/or in thehydrodecontamination of the aforesaid petroleum fraction boiling abovethe boiling range of reformer feed with or without recompression betweenthe reformer and the hydrodecontaminating unit or units. It is anotherobject of the present invention to provide a means forhydrodecontaminating domestic heating oil to produce stabilized domesticheating oil stabilized with respect to at least one of color andsediment, to hydrodecoutaminate reformer feed to produce treatedreformer feed containing not more than 1 ppm. of nitrogen, and not morethan 20 ppm. of sulfur and to reform the aforesaid treated reformer feedunder reforming conditions of temperature and pressure in the presenceof particle-form solid platinum-group reforming catalyst andhydrogen-containing gas to produce a reformate of. improved octanerating and hydrogen-containing gas wherein the aforesaidhydrogen-containing gas, hereinafter designated excess reformer gas, isused in the hydrodecontamination of the aforesaid reformer feed and/ orin the hydrodecontamination of the aforesaid petroleum fraction boilingabove the boiling range of reformer feed with or without recompressionbetween the reformer recycle gas compressor and the hydrodecontaminatingunit or units.

It is a further object of the present invention to provide d. a meansfor hydrodecontaminating a domestic heating oil in conjunction with ahigh nitrogen naphtha (as defined hereinbefore) to produce a stabilizeddomestic heating oil (as defined hereinbefore) and an at least partiallyhydrodecontaminated high nitrogen naphtha which when mixed with a lownitrogen naphtha (as defined hereinbefore) to form a blend, the blendcan be hydrodecontaminated in existing reformer feed preparationfacilities to provide a reformer feed containing not more than 1 ppm. ofnitrogen, to blend said at least partially hydroecontamineted highnitrogen naphtha with low nitrogen naphtha to form a blend,hydrodecontaminating said blend to produce a reformer feed containingnot more than 1 p.p.m. of nitrogen, and reforming said blend in thepresence of particle-form solid platinum-group reforming catalyst andhydrogen under reforming conditions of temperature and pressure toobtain a reformate having an octane rating higher than that of saidblend wherein hydrogen-containing gas produced in said reforming is usedin the hydrodecontamination of said blend and in thehydrodecontamination of said domestic heating oil and said high nitrogennaphtha with or without recompression between the reformer recycle gascompressor and the hydrodecontaminating units. Other objects andadvantages of the present invention will become apparent to thoseskilled in this art from the following discussion thereof taken inconjunction with the drawings in which FEGURE 1a is a fiowsheetillustrating in a diagrammatic manner the flow of gases and liquids in aunit hydrodecontaminating a petroleum fraction boiling above the boilingrange of reformer feed or the aforesaid petroleum fraction and highnitrogen naphtha employing the hydrogen-containing gas from apretreating unit together with a portion of a hydrogen sulfide recoveryunit; and

FIGURE lb is a fiowsheet illustrating the separation of the hydrotreatereffluent into a gaseous fraction, a reformer feed, and a treatedpetroleum fraction boiling above the boiling range of reformer feed andreforming of the reformer feed; and

FIGURE 10 is a fiowsheet illustrating the separation of the pretreatereffluent into a gaseous fraction and reformer feed; and fractionation ofthe final reformer effluent into reformer gas and reformate.

Illustrative of the present invention is the hydrodecontamination of agas oil to produce an improved gas oil of lower sulfur and/ or nitrogencontent suitable for catalytic cracking with improved results and an atleast partially decontaminated reformer feed. When the quantity ofpartially decontaminated naphtha produced in the hydrodecontamination ofthe aforesaid gas oil is insufficient to supply the total throughputcapacity of the pretreater and reformer or when the nitrogen content ofthe reformer feed is higher than that which can be reduced to about 1ppm. in existing pretreating facilities, the reformer feed produced inhydrodecontaminating the gas oil is blended with a naphtha to provide ablend in pretreater-and-refornier capacity volume having a nitrogencontent which can be reduced to 1 ppm. in existing re former feedpreparation facilities. The reformer feed produced in thehydrodecontamination of the gas oil, i.e., the autogenous refinerreformer feed alone or blend as described hereinbefore ishydrodecontaminated in a pretreater to produce a treater reformer feedcontaining not more than about 1 ppm. of nitrogen. The treated reformerfeed is reformed under reforming conditions of temperature and pressureto produce a reformate of higher octane rating than that of the treatedreformerfeed and hydrogen in excess of that required to maintain atolerable deposition of coke on the particle-form reforming catalyst.

The following are illustrative for the hydrodecontarn ination of apetroleum fraction boiling above the boiling range of reformer feed,i.e., boiling above a temperature within the range of about 350 to about420 F., pretreating the autogenous reformer feed alone or blended Hydrotreater r Refiner Catalyst: about 1.5 to about 3.8 percent by weightof cobalt oxide; about '7 to about 16 percent by weight of molybdenumoxide Carrier: alumina Hydrodecontaminating conditions:

Broad Preferred Reaction pressure, p.s.i.g 200 to 1,000 390 to 850Reaction temp, F 550 to 850 700 to 800 Space velocity (LHSV) v./hr./v 2to 10 4 to 6 Hydrogen circulated per barrel of refiner feed, s.c.f 200to 2,000 320 to 1, 000 Mols of hydrogen/moi of hydrocarbon 0. 4 to 3. 8018 to 2. 7

S.c.f.stan (lard cubic feet.

Pretreater Catalyst: about 1.5 to about 3.8 cobalt oxide; about 7 toabout of molybdenum oxide Carrier: alumina Hydrodecontaminatingconditions:

percent by weight of 16 percent by Weight Broad Preferred Reactionpressure, p.s.i.g 100 to 1, 000 400 to 500 Reaction temperature, F 600to 850 (575 to 725 Space velocity (noisy), v./hr. 1 to 10 2. to 5Hydrogen circulated per barrel of reformer feed, sci 350 to 2, 500 400to 800 Reformer Catalyst: 0.6 percent by weight of platinum; 0.6 percentby weight of chlorine Carrier: alumina Reforming conditions:

Broad Reaction pressure, p.s.i.g. 100 to 1,000 Reaction temperature, F.800 to 1,000 Space velocity (LHSV), v./hr./v. 0.5 to Mole oihydrogcn/mol of reformer feed 4 to Thus, a petroleum fraction boilingabove the boiling range of reformer feed, i,e., boiling above atemperature within the range of about 350 to about 420 F, e.g.,kerosine, domestic heating oil, diesel fuel, gas oil and the like isdrawn from a source not shown through pipe 1 by pump 2. Fun-1p 2discharges the petroleum fraction into pipe 3: at a pressure in excessof that in absorber 15. The petroleum fraction flows through pipe 3 topipe A portion of the petroleum fraction flows from pipe d to pipe 5under control of valve 6 to the top of absorber 1b. The balance of thepetroleum fraction flows from pipe 4 through pipe '7 to pipe 2%. In pipe8 a portion or all of the balance of the petroleum fraction flowsthrough heat exchanger 9 dependent upon the tempcrature to be maintainedin absorber 15. in heat exchanger 9 the portion of the balance of thepetroleum fraction flowing through pipe 8 is in indirect heat exchangerelation with stabilized petroleum fraction, e.g., gas oil. The heatedpetroleum fraction boiling above the boiling range of reformer feed,i.e., boiling above a temperature within the range of about 350 to about420 F, eg, gas oil and so designated hereinafter, flows from heatexchanger through pipe 12 to pipe 14. The remainder of the balance ofthe gas oil, it any, flows through pipe it under control of valve 11 topipe 12 Where the unheated and heated portions of the balance of the gasoil mix and flow under control of valve 113 through pipe 14 to absorberThe distribution of the gas oil between pipes 5 and 1d is dependent uponthe quantity of gas flowing from low pressure diethanoiamiue absorber 83when used through conduit 36 and the quantity of gas flowing fromknock-out pot 55 through conduit 57. That is to say, the fiow of oilthrough pipes 5 and 14 and the how of gases through conduits 58 and asare balanced to remove substantially all of the C and heavierhydrocarbons from the gases and to remove water and heat exchangedeposit precursors from the gas oil. The distribution of the gas oilbetween pipes b and is dependent upon maintaining the maximumtemperature in absorber 15 at which substantial absorption of C andheavier hydrocarbons by the oil and stripping of Water, oxygen anddeposit precursors occurs. Usually, a temperature within the range ofabout to about F. is satisfactory in absorber 15.

The stripped gases and absorbed water, oxygen, etc. are vented fromabsorber 15 through conduit 16 to the refinery fuel main. The gas oilflows from absorber 15 through pipe 17 to the suction side of pump 18.

Pump 18 discharges the gas oil into pipe 15 at a pressure greater thanthe pressure in hydrotreater 335. The gas oil flows through pipe 19 toheat exchanger 20. in heat exchanger 20 the gas oil is in indirect heatexchange relation with the overhead from high temperature flash drum 37flowing from heat exchanger through conduit 39. From heat exchanger 20the gas oil flows -throughpipe 21 to heat exchanger 22 where the gas oilis in indirect heat exchange relation with treated gas oil flowing fromheat exchanger as through pipe lilii. From heat exchanger 22 the gas oilflows through pipe .23 to heat exchanger 4 where the gas oil is inindirect heat exchange relation with the overhead of high temperatureflash drum 3'] flowing therefrom through conduit 38. From heat exchanger24 the gas oil flows through pipe 25 to heat exchanger 26 where the gasoil is in indirect heat exchange relation with the total efiiuent fromhydrotreater 33 flowing to heat exchanger 26 through conduit 35. Onlythat portion or" the gas oil flows through heat. exchanger 25 which isrequired to reduce the temperature of the hydrotreater efiluent to thatat which the separation (described hereinafter) desired in hightemperature flash drum 37 occurs. The balance of the gas oil lay-passesheat exchanger 26 and flows through pipe 27 under control of valve 23 topipe 20. From heat exchanger 26 the heat exchange-d portion of the gasoil flows through pipe 25 where the heat exchanged portion of the gasoil and the balance, if any, of the gas oil mix and flow to coil 30 inheater 311. i

in heater 31 the temperature of the gas oil is raised to ahydrodecontamination temperature within the range of about 550 to about800 F. as described hereinbefore. From heater 31 the gas oil flowsthrough pipe 32 to hydroreater 33. Hydrogen-containing gas flowingthrough conduit 34 from heat exchanger 63 flows into hydro-treater 33 toprovide about 200 to about 2000 s.c.f. (standard cubic feet) of hydrogenper barrel of gas oil part or all of which ilows from the pretreaterabsorber 1110 through conduits P-2 l5 rand T l-245 as describedhereinafter.

The intimately mixed heated gas oil and the hydrogen-containing gas flowdownwardly through hydrotreater 33 in contact with the hydrogenatingcatalyst having hydrodesulfurizing and/or hydrodenitrogenizingcapabilities described hereinbciore. The hydro'trea er effluent flowsfrom hydrotreater 33 through conduit 35 to heat exchanger 26 where thehydrctreater efduent is in indirect: heat exchange relation with atleast a portion of the treated gas oil as described hereinbefore.

From heat exchanger 26 the cooled hydrotreater eiliueut flows throughconduit 36 to high temperature ilash drum 37. A temperature ismaintained in high temperature flash drum 37 to provide a balanced heatload to reduce the stripping steam requirement in stripper 75 and tovolatilize at the existing pressure a major portion of the hydrocarbonsboiling within the boiling range of reformer feed. The aforesaidvolatile hydrocarbons are taken as: overhead, designated hereinafterhigh temperature overhead. The unvaporized hydrocarbons are designatedhigh temperature bottoms.

The high temperature overhead comprises hydrogen volatile hydrogenderivatives of contaminants, e.g., hy' drogen sulfide, ammonia, etc, andC hydrocarbons The high temperature overhead flows from high temperatureflash drum 37 through conduit 38 to heat exchanger 24 where the hightemperature overhead is in indirect heat exchange relation with the gasoil as described hereinbefore. From heat exchanger 24 the hightemperature overhead flows through conduit 39 to heat exchanger 29 wherethe high temperature overhead is in indirect heat exchange relation withthe gas oil as described hereinbefore. Prom heat exchanger 2% the hightemperature overhead flows through conduit 46 to cooler 41 where thehigh temperature overhead is coo-led to a temperature as low as possiblewith normal cooling water, so as to produce as high a hydrogenconcentration as possible in the overhead from separator 43. From cooler41 the cooled high temperature overhead flows through conduit 42 to lowtemperature separator 43.

In separator 43 an equilibrium flash separation is obtained to providean overhead comprising hydrogen, hydrogen derivatives of contaminants,e.g., hydrogen sulfide and ammonia, and hydrocarbons boiling below theboil ing range of reformer feed usually comprising C to C and traces ofC and C hydrocarbons which is taken through conduit 44- to high pressurehydrogen sulfide ab sorber 45.

Presently it is preferred to employ diethanolamine as the absorbent forthe hydrogen sulfide. Lean aqueous 'diethanolamine solution pumped atlow pressure from diethanolamine (DEA) stripper 46 by pump 4% throughpipe 49 to heat exchanger 5d and a cooler not shown and through pipe 51to pump 52 as described hereinafter is pumped by pump 5'2 through pipe53 to the top of high pressure DEA absorber 35. The pressure in highpressure DEA absorber is substantially that of low temperature separator43 less pressure drop due to intervening piping.

In high pressure DEA absorber t5 the low temperature overhead flowsupwardly countercurrent to the downwardly flowing DEA solution. The lowtemperature overhead stripped of hydrogen sulfide flows from highpressure DEA absorber 45 through conduit 54 to knock-out pot 55. Inknock-out pot 55 any entrained DEA solution falls out of the gas and isdrawn-off through pipe 55. The gas comprising hydrogen and Chydrocarbons and designated refiner recycle gas fiows from knock-out pot55 through conduit 57.-

When the excess reformer gas is sufiicient in quantity to supply all ofthe hydrogen gas required for circulation in the refining unit all ofthe refiner recycle gas is vented through conduit 58 under control ofvalve 59 to absorber 15 as described hereinbefore. However, when theexcess reformer gas is less than the amount of hydrogen required forcirculation in the refiner or hydrotreater section the deficiency ofexcess reformer recycle gas is made up by recycling a portion of therefiner recycle gas. Under these conditions only that portion of therefiner recycle gas is vented through conduit 5% which is required tokeep the pressure at a prede.errnined level. The balance of the refinerrecycle gas flows through conduit 57 to the suction side of refinerrecycle gas compressor so.

At this point the use of pretreater gas containing hydrogen under threeconditions of operation will be described. The first condition is thatexisting when the hydrotreater or refiner is operating at a pressure atleast about 30 p.s.i. lower than the pressure at the pretreater absorber110 and all of the refiner or hydro-treater circu lating gas is suppliedby the reformer. The second condition is that existing when thehydrotreater or refiner is operating at a pressure higher than thepressure at the pretreater absorber 110 and all of the refiner orhydrotreater circulating gas is supplied by the reformer. The thirdcondition is that existing when the reformer does not produce suflicientexcess reformer gas to satisfy the demand for circulating hydrogen inthe hydrotreater or refiner and the pressure in the hydrotreater orrefiner is at least about 30 psi. lower than the pressure at thepretreater absorber Hit or the pressure in the refiner is higher thanthat at the pretreater absorber.

For the first condition, i.e., the refiner pressure is at least about 30p.s.i. less than the pressure at the pretreater absorber ill) and theexcess reformer gas is sufficient to supply all of the hydrogen requiredfor circulation in the hydrotreater or refiner circuit or unit (in otherwords, the hydrogen-containing gas is used in the refiner unit on a oncethrough basis) the hydrogen-containing gas flows from the pretreatcrabsorber ilfi through conduits F-245 and H245 to conduits 61 and s7 andthence to conduit 62. The pretreater cascade gas flows through conduit62 to heat exchanger 63 where the pretreater cascade gas is in indirectheat exchange relation with the bottoms of light products stripper 7'5flowing from heat exchanger 69 through pipe From heat exchanger 63 thepretreater cascade gas flows through conduit 34 to hydrotreater orrefiner 33 as described hereinbefore.

For the second condition under Which the excess reformer gas issufiicient to meet the demand for the amount of hydrogen required forcirculation in the refiner circuit but the refiner circuit is at ahigher pressure than the pressure at the pretreater absorber lltl thepretreater cascade gas flows from pretreater absorber illfi throughconduits P445 and 1-1-2 35 to conduit 64 under control of valve 65 andthence to compressor 66. Compressor 66 discharges the pretreater cascadegas intoconduit 67 at a pressure higher than that in hydrotreater orrefiner 33. The recomprcssed preheater cascade gas flows through conduit67 to conduit 62. The recompressed pretreater cascade gas flows throughheat exchanger 63 and conduit to hydrotreater or refiner 33. As underthe first condition described hereinbcfore, the refiner recycle gas isvented through conduits 5'7 and 58 to absorber 15 and through conduit 16to the refinery fuel main.

For the third condition, the supply of excess reformer gas is less thanthat required for circulation in the refiner unit and (a) thehydrotreater pressure is at least about 30 p.s.i. less than the pressureat the pretreater absorber lit) or (b) the hydrotreater pressure ishigher than the pressure at the pretreater absorber 11% When thehydrotreater is operated at a pressure at least about 30 psi. less thanthe pressure at the pretreater absorber 114 the pretreater cascade gasflows from absorber through conduits P-ZQE and H4345 to conduit 61 andthence through conduit 67 to conduit 62. Sufficient of the refinerrecycle gas to provide the total volume of hydrogen required forcirculation in the refiner unit flows through conduit 57 to the suctionside of compressor 69. Compressor 6d recompresses the refiner recyclegas to a pressure higher than the pressure in hydrotreater 33 but nothigher than the pressure of the pretreater cascade gas in conduit 67.The mixture of refiner recycle gas and pretreater cascade gas fiowsthrough conduit 62 to heat exchanger 63 and conduit 34 to hydrotreater33. The overhead from low temperature flash drum as after removal ofhydrogen sulfide flows through conduit 57. Part of the refiner recyclegas is diverted to the absorber 15 as described hcreinbefore to avoid abuild-up of pressure in the system and the balance is recycled.

When the hydrctreater is operated at a pressure higher than that at thepretreater absorber and the volume accuser of excess reformer gas isless than the required volume of refiner circulating hydrogen, thepretreater cascade gas flows from pretreater abs rber lit) throughconduits P445 and H4345 to condt' under control of valve 65' and thesuction side of compressor 66.

through pipe 81. Hydrogen, hydrogen sulfide and light hydrocarbons flowfrom accumulator 8% through conduit 32 to low pressure DEA absorber $3.Alternatively, the hydrogen, hydrogen sulfide and light hydrocarbonsflow Compressor directly to the refinery fuel gas main. 66 dischargesthe pretreater cascade gas into conduit 67 In low pressure DEA absorber83 the hydrogen, hyat a pressure higher than that in hydrotreater Thedrogen sulfide and light hydrocarbons flow upwardly volume of circuiaing hydrogen in excess of that supplied countercurrent to downwardlyflowing lean aqueous diin the prctreater cascade gas is supplied by therefiner ethanolamine solution flowing from pipe 51 through pipe recyclegas flowing in conduit 57 to the suction side of 84 under control ofvalve 85. The gas stripped of hycompressor Compressor as discharges therepresdrogen sulfide flows from low pressure DEA absorber 83 suredrefiner recycle gas into conduit 62 at substantially through conduit 86to absorber 15. the pressure of the compressed pretreater cascade gas inThe hydrocarbons boiling in the boiling range of reconduit 67. Themixture of repressured refiner recycle former feed and having a maximumboiling point of gas and compressed pretreater cascade gas flows throughabout 350 to about 420 F. flow from accumulator 8t conduit 62 to heatexchanger 63 and conduit to hythrough pipe W1. A portion suflicient foruse as reflux drotreater 33. flows through pipe 88 under control ofvalve 89 to pump illustrative of the foregoing conditions are the fol-9. Pump 9% discharges the reflux portion of the conlowing: dcnsedportion of the light products stripper overhead 1 Required ReformerPretrcatcr Reo'urcd Reformer Prctrcatcr Refincr circulating cascade gasrecycled circulating Prctrcctcr Rcfiner gas cascade cascade gas in gas,s.c.[./ to pretreater, gas in cascade gas, recycled, gas was gaspresnearer, bbLotprcs.c.f./n'ol.ot refiner, s.c .f./bbl.oi s.c.f./bbl.otsure, sure, s.c.l./bbl. ol treater pretreatcr s.c.f./bbl. of refinerrefiner psig. p.s.i.g. preftrgcgter feed feed rcfinerfccd feed food 500420 390 202 20.2 0 J 319 319 0 500 420 390 0 1, 025 340 635 500 sec 2.430 200 2, 2:50 500 420 550 500 150 350 1., 000 97 500 420 850 5 0 1,000 ass e14 500 420 s50 333 0 1, 000 255 500 420 see 534 5st 0 1, 000225 775 500 420 750 592 592 0 1, 000 622 37s Having described the flowof the high temperature into pipe 91 through which the reflux portionflows to overhead and the flow of the low temperature overhead, lightproducts stripper '75 for use as reflux. The balance the flow of the lowtemperature bottoms and the flow of of the condensed portion of thelight products stripper the high temperature bottoms will now bedescribed. As overhead flows through pipe 37 to fractionator 92.Alstated hereinbetore a temperature as low as normally obternatively,the condensed hydrocarbons in accumulator tained by water cooling ismaintained in low temperature 4t) 8t) flow directly to pretreaterabsorber ltd. flash drum 43. The separation is not sharp and conseinfraetionator 92 a temperature is maintained at quently the lowtemperature flash drum bottoms is fracwhich (3.; and lighterhydrocarbons are volatile. The tionated a second time. Accordingly, thelow tempera- C and lighter hydrocarbons are taken overhead through tureflash drum bottoms flows through pipe 63 to heat pipe )3. The C overheadflows through pipe 93 to exchanger 69 where the low temperature flashdrum bot- 4.5 cooler as Where the C; overhead is cooled to a temperatomsis in indirect heat exchange relation with not light ture at which C andheavier hydrocarbons are condensed. products stripper bottoms flowingfrom pump through The condensed and uncondensed C overhead flows pipeHi7. From heat exchanger the low temperature through conduit 95' toaccumulator as. Uncondenscd flash drum bottoms flows through pipe topipe 71. hydrocarbons, C to C flow from accumulator 96 The hightemperature flash drum bottoms is hydrocarbons through pipe Ittli to therefinery gas plant for the recovboiling above the reformer feed range.The high tem cry of light hydrocarbons or to the refinery fuet gas main.perature flash drum bottoms flows through pipe to Condensed C overheadflows from accumulator 96 heavy products stripper '73 where the bottomsis stripped through pipe 97 under control of a valve not shown to bysteam fed to the top plate. in heavy products stripper facilities forseparating isobutane from normal butane. 73 a temperature is maintainedat which hydrocarbons A portion of the condensed C overhead is divertedboiling in a range which gives too low a flash point to through pipe 5 3to the suction side of pump 99. Pump the stripper bottoms, are takenoverhead through pipe 99 discharges the diverted portion of thecondensed C 74 to pipe 71 where the heavy products stripper overoverheadinto pipe 1% through which the diverted overhead is mixed with the lowtemperature flash drum bothead flows to fractionator $2 for use asreflux. The bottoms. The mixture of heavy products stripper overhead notoms in fractionator 92, i.e., hydrocarbons boiling in the and lowtemperature flash drum botoms flows through boiling range of reformerfeed and having a maximum pipe 71 to light products stripper '75. Thebottoms from boiling point of about 350 to about 420 F. and preferheavyproducts stripper '73 flows through pipe 76 to the ably comprising C andheavier hydrocarbons flows bottom of light products stripper '75.through pipe M2 to the suction side of pump 193. Pump In light productsstripper 75 a temperature is main- M33 discharges the bottoms into pipe104 through which tained at which hydrocarbons boiling at a temperaturethe bottoms flow to pipe and the pretreater absorber. which gives toolow a flash point to the bottoms of strip- Returnins now to the lightproducts stripper '75; the per '75 are volatile and taken overheadthrough pipe 77. hydrocarbons boiling above the minimum temperature Thelight products stripper overhead flows through pipe needed to give thedesired flash point to the bottoms are '77 to cooler where the lightproducts stripper overthe bottoms in light products stripper 75. Thebottoms head is cooled to a temperature at which C and heavy is thetreated gas oil. The bottoms flows from light prodhydrocarbons arecondensed with small amounts of lighter ucts stripper through pipe M5 tothe suction side of hydrocarbons. The cooled light products stripperoverpump 1%. Pump 1% discharges the hot treated gas head flows fromcooler 73 through conduit T9 to accuoil into pipe 107. The treated gasoil flows through pipe mulator iii In accumulator 8t) water is drawn off75 M7 to heat exchanger d9 where the treated gas oil is H. in indirectheat exchange relation with the bottoms of the low temperature flashdrum flowing therefrom through pipe 68. From heat exchanger 69 thetreated gas oil flows through pipe 108 to heat exchanger 63 where thetreated gas oil is in indirect heat exchange relation withhydrogen-containnig gas flowing to hydrotreater or refiner 33. From heatexchanger 63 the treated gas oil,

flows through pipe 109 to heat exchanger 22 where the treated gas oil isin indirect heat exchange relation with the gas oil feed. From heatexchanger 22 the treated gas oil flows through pipe 233 to heatexchanger where the treated gas oil is in indirect heat exchangerelation with a portion of the gas oil feed whereby the temperature inabsorber I is maintained as described hereinbefore. From heat exchanger9 the treated gas oil flows through pipe 234 to cooler 227. In cooler227 the temperature of the treated gas oil is lowered to that at whichthe most volatile constituent is condensed. From cooler 227 the cooledtreated gas oil flows through pipe 22% to storage, further treatment,addition of additives and the like dependent upon its use.

Those skilled in the art will r cognize that the fractionations achievedin the high temperature flash drum 37, the low temperature flash drum43, the heavy products stripper 73, the light products stripper 75 andfractionator 92 are those of separating the hydrotreater or refinereffluent into a gaseous fraction comprising the major portion of thehydrogen of the hydrotreater or refiner eflluent with as small apressure drop as practical, a hydrocarbon fraction boiling in the rangeof reformer feed and having a maximum boiling point within the range ofabout 350 to about 420 F., a light hydrocarbon fraction boiling belowthe range or reformer feed, and a heavy hydrocarbon fraction boilingabove the boiling range of reformer feed. Those skilled in the art willrecognize that any method other than that shown to accomplish theaforesaid separation can be substituted for that shown.

Before tracing the path of the (3 hydrocarbons separated as bottoms infractionator 92 through the pretreating and reforming units the hydrogensulfide absorption unit will be described. While diethanolamine solutionhas been used to illustrate the removal of hydrogen sul fide from thegaseous fraction of the hydrotreater or refiner efliuent those skilledin this art will recognize that other absorbents for hydrogen sulfidecan be used. Furthermore, when necessary or desirable, other componentsof the gaseous fraction can be removed from the gaseous fraction of thehydrotreater eifluent.

As has been described hereinbefore, hydrogenand hydrogensulfide-containing gases flowing from accumulator 80 at relatively lowpressure and hydrogenand hydrogen sulfide-containing gases flowing fromlow temperature flash drum 43 at relatively high pressure are treatedfor the removal of hydrogen sulfide.

Lean absorbent, in the illustration diethanolamine (DEA), flows fromstripper 46 through pipe 47 to the suction side of pump Pump 43discharges the lean DEA into pipe 49 at a pressure about that of the gasflowing from accumulator 80 through conduit 32. The low pressure leanDEA flows through pipe 49 to heat exchanger 50 where the low pressurelean DEA is in indirect heat exchange relation with the relatively coldfat DEA solution flowing from absorber 03 through pipe 237. From heatexchanger 50 the low pressure lean DEA solution flows to a cooler (notshown) where it is cooled by indirect heat exchange with water and menflows through pipe 51 to the suction side of pump 52. A portion of thelow pressure lean DEA solution is diverted through pipe 84 under controlof valve 85 to the top of absorber 83. In absorber 83 the low pressurelean DEA solution flows downwardly countercurrent to the upwardlyflowing low pressure gas from accumulator S0. The balance of the lowpressure lean DEA solution is discharged into pipe 53 by pump 52 at apressure at least equal to that of the gas in conduit 44. The highpressure lean DEA flows through pipe 53 to the top of absorber 45. Thelean DEA solution flows downwardly through absorber 4-5 countercurrentto the upwardly flowing high pressure gas from conduit The fat highpressure DEA solution flows through pipe 235 and pressure reducing valve236 to the lower part of absorber 03. The fat DEA solution from absorberand the fat DEA solution in absorber 83 mix and flow from absorber 83through pipe 237' to heat exchanger 50. In heat exchanger the fat DEAsolution is in indirect heat exchange relation with the hot lean lowpressure DEA solution as described hereinbefore. From heat exchanger 50the fat DEA solution flows through pipe 238 to DEA stripper 46. In anysuitable manner as by steam coil .39 a temperature is maintained instripper 46 at which hydrogen sulfide is volatilized. The hydrogensulfide and water vapor flows from stripper 46 through conduit to cooler231 where the vapors are cooled to a temperature at which water iscondensed. The cooled vapors flow through conduit 232 to accumulator116. In accumulator 116 the condensed water drops out. The water isdrawn from accumulator "rte through pipe 13.7 by pump I18. Pump 113discharges the water into pipe 110 through which the water flows tostripper 46 for use as reflux. The hydrogen sulfide gas flows fromaccumulator 116 through conduit to means for the recovery of sulfur.

Returning now to fractinator 92 the course of the bottoms thereof, i.e.,the reformer feed produced in hydrodecontaminating the petroleumfraction boiling above the boiling range or reformer feed, i.e., boilingabove a temperature Within the range of about 350 F. to about 420 R,will be traced. The reformed feed produced in the hydrodecontaminationof the gas oil for example and hereinafter designated autogenousreformer feed flows through pipe 102 to the suction side of pump 103.Pump 103 discharges the autogenous reformer feed into pipe 104 throughwhich the autogenous reformer feed flows to pipe .242 (see FIGURE 1b).

Usually the quantity of'autogenous reformer feed is not suflicient tomake it practical to operate a pretreating and reforming unit using theautogenous reformer feed as the sole feed thereto. Consequently, theautogenous reformer feed is mixed with extraneous naphtha. Furthermore,existing reformer feed preparation facilities usually are not capable ofhydrodecontaminating reformer feed containing more than l0 ppm. ofnitrogen to produce a reformer feed containing not more than 1 ppm. ofnitrogen. Therefore the autogenous reformer feed when containing morethan 10 ppm. of nitrogen is blended with a low nitrogen naphtha toproduce a pretreater blend containing nitrogen not in excess of thatwhich can be reduced to 1 ppm. in existing reformer feed preparationfacilitie. In other words, depending upon the nitrogen content and thevolume of autogenous reformer feed, the autogenous reformer feed isblended with an extraneous reformer feed in quantity to produce thevolume of blend for economical operation of the pretreater and reformer;the extraneous reformer feed having a nitrogen content such that whenblended with the autogenous reformer feed in the aforesaid proportionsthe blend has a nitrogen content which can be reduced to not more than 1ppm. in existin reformer feed preparation facilities.

Thus, for example, a reformer and the feed preparation facilitiestherefore are designed to treat an economic minimum of 10,000 barrelsper day. The autogenous reformer feed produced is 1,000 barrels per dayand has a nitrogen content of 15 ppm. The reformer feed preparationfacilities are designed to reduce the nitrogen content of a reformerfeed from 10 ppm. to 1 ppm. In this instance the 1,000 barrels per dayof autogenous reformer feed is mixed with 9,000 barrels of extraneousreformer feed containing not more than about 9 ppm.

of nitrogen. On the other hand, with the same reformer feed preparationfacilities and 1,000 barrels per day of autogenous reformer feed havinga nitrogen content of 90 ppm. the autogenous reformer feed is mixed with9,000 barrels per day of extraneous reformer feed having a nitrogencontent of not more than about 1 ppm. Those skilled in the artunderstand that reformer feed preparation facilities can be designed totreat a reformer feed having a nitrogen content greater than 10 ppm. toreduce the nitrogen content thereof to 1 ppm.

To provide the required reformer feed blend, extraneous reformer feedmeeting the requirements set forth hereinbefore, for example,straight-run naphtha is drawn from a source not shown through pipe 24-9by pump 241. The extraneous reformer feed, e.g., straight-run naphthaand so designated hereinafter is discharged by pump 241 into pipe 242 ata pressure greater than that in pretreater absorber lit). The autogenousreformer feed flowing through pipe 1G4 at substantially the samepressure as that under which the straight-run naphtha is in pipe 242mixes in pipe 242 to form the pretreater blend having a nitrogen contentnot in excess of that which can be reducedto 1 ppm. in pretreater 131.The pretreater blend flows in part through pipe under control of valve244 and in part through pipe 242 to pretreater absorber iii). Inpretreater absorber lib the blend is in contact with gas flowing frompretreater liquid-gas separator 145 through conduit 132 and branch 1%under control of valve 217.

The distribution of pretreater blend between pipes 242 and 243 and thedistribution of gas between conduit 132. and branch 146 is balanced toremove substantially all of the C and heavier hydrocarbons from the gaswhile removing substantially all the water, oxygen and heat exchangerdeposit precursors from the pretreater blend.

The gas, containing hydrogen, hydrogen sulfide and other components ofthe liquid-gas separator edges or pretreater cascade gas not absorbed bythe pretreater blend flows from pretreater absorber llli through conduit111 under control of valve 112 to conduits P-Zd-S and i i-2 5 and thenceto conduit 61 or conduit 64 as described hereinbefore. The balance ofthe gas not flowing to the hydrotreating or refining unit, if any, flowsthrough conduit 113 under control of valve li t to sulfur recovery or tothe refinery fuel main.

The pretreater blend including hydrocarbons absorbed from the pretreatercascade gas but substantially devoid of water, oxygen and heat exchangerdeposit precursors flows from pretrcater absorber fit through pipe 246to the suction side of pump 247. Pump 2 discharges the pretreater blendinto pipe 2% through which the pretreater blend and absorbedhydrocarbons (hereinafter designated pretreater blend) flow to heatexchanger 249.

In heat exchanger 249 the pretreater blend is in indirect heat exchangerelation with the pretreater effluent flowing through conduit ml. Fromheat exchanger 249 the pretreater blend flows through pipe lit to heatexchanger 121 Where the pretreater blend is in indirect heat exchangerelation with the pretreater effluent flowing from the pretreater 131through conduit 138. From heat exchanger 1231 the pretreater blend flowsthrough pipe 122 to coil 123 in heater 1.24.

in heater 1 J- the pretreater blend is heated to a ternperature suchthat when mixed with hydrogen-containing gas to form a pretreater chargemixture, the charge mixture will be at a hydrodecontaminatingtemperature within the range set forth hereinbetfore for pretreating.From heater 124- the heated pretreater blend flows through conduit 125to conduit 126. In conduit 126 the heated pretreater blend is mixed withhydrogen in the propertions set forth hereinbefore for pretreating.

The hydrogen is supplied wholly or in part as excess reformer gasflowing from reforming liquid-gas separator through conduit 21% undercontrol of valve 219. When none of the pretreater cascade gas isrecycled through the pretreating unit as described hereinafter and thepretreater 3'31 is operating at a pressure at least 25 psi. lower thanthe pressure in reformer liquid-gas separator 138 excess reformer gas,i.e., reformer cascade gas, flows from reformer liquid-gas separator ths through conduit 21% under control of Valve 22%) to conduit $.25 Wherethe excess reformer gas is mixed with the pretreater blend. When thepretreater is operating at a pressure higher than the pressure inreformer liquid-gas separator 188 the excess reformer gas, i.e.,reformer cascade gas flows through conduit 21% (valve 22% closed) andconduit 12") under control of valve 128 to the suction side ofpretreater compressor 129. Pretreater com pressor 129 discharges theexcess reformer recycle gas into conduit 13% at a pressure higher thanthe pressure in pretreater 131. The compressed excess reformer recyclegas flows through conduit 13% to conduit 126 where it is mixed With theheated pretreater blend in the proportions set forth hereinbefore underpretreating.

When the volume of the excess reformer recycle gas is less than thevolume of hydrogen to be circulated in the pretreating unit a portion ofthe pretreater gas is recycled. Thus, when the excess reformer hydrogenis about 500 s.c.f. per barrel of pretreater blend and about 1,000s.c.f. of hydrogen are circulated in the pretreater unit about 500 s.c.fof pretreater hydrogen is recycled. Thus, with the prctreater operatingat a pressure at least 25 psi. less than the pressure in the reformerliquid-gas separator 3183 about 560 s.c.f. of hydrogen per barrel ofpretreater blend as reformer cascade gas flows through conduit 21% undercontrol of valve 225% to conduit where the excess reformer gas is mixedwith the pretreater blend. About 500 s.c.f. of hydrogen as pretreatercascade gas per barrel of pretreater blend is diverted from conduit 132through conduit 134 under control of valve 135 to the suction side ofcompressor 1%. Compressor E36 discharges the diverted portion of thepretreater cascade gas into conduit at a pressure higher than thepressure in pretreater llftil. The compressed por tion of the pretreatercascade gas flows through conduit to conduit 325 where the compressedportion of the pretreater cascade gas is mixed with the heatedpretreater blend. Similarly, when the pretreater pressure is greaterthan the pressure at reformer liquidgas separator and the volume ofexcess reformer hydrogen as reformer cascade gas is less than the volumeof hydrogen being circulated in the pretreating unit the excess reformerhydrogen as reformer cascade gas flows through conduit 218 (valve 22%closed) to conduit 127 under control of valve 128 and thence to thesuction side of compressor 12?. Compressor 12% discharges the compressedreformer cascade gas into conduit 1% at a pressure higher than thepressure in pretreater 131. The compressed reformer cascade gas flowsthrough conduit 131'? to conduit where the compressed reformer cascadegas is mixed with the heated pretreater blend and recycled pretreatergas. The recycled pretreater gas flows from conduit 132 through conduitunder control of valve to the suction side of compressor Compressor 1%discharges the recycled pretreater gas into conduit 137 at a pressurehigher than that in pretreatcr and about equal to the pressure inconduits and The sum of the volume of hydrogen as pretreater gas and thevolume of hydrogen as reformer cascade gas is about equal to the volumeof hydrogen circulated in the pretreating unit as set forthhereinbefore.

The heated pretreater blend together with the hydrogen wholly asreformer cascade gas or partly as reformer cascade gas and recycledpretreater gas liovvs downwardly through pretreater underhydrodecontaminating conditions asset forth hereinbefore in contact witha particle-form hydrogenating catalyst having hydrodesulfurizing and/orhydrodenitrogenizing ca tbilities. The pretreater effluent flows throughconduit 133 to heat exchanger 121 Where the prctreater efil cut is ininspanner direct heat exchange relation with the pretreater blendflowing through pipe 12% as described hereinbefore. From heat exchanger121 the pretreater efiluent flows through conduit 13% to heat exchanger141). In heat exchanger 14-11 the pretreater effluent is in indirectheat exchange relation with the condensed portion of the pretreatereffluent flowing from heat exchanger 15%) through pipe 151. From heatexchanger 1% the pretreater efiluent flows through conduit 14-1 to heatexchanger 24-9 where the pretreater effluent is in indirect heatexchange relation with the pretreater blend as described hereinbefore.From heat exchanger the pretreater effluent flows through conduit 142 tocooler 153.

In cooler 143 the pretreater effluent is cooled to a temperature atwhich hydrocarbons boiling in the boiling range of reformer feed arecondensed. Depending upon the temperature of the pretreater eflluent andthe temperature to be maintained in liquid-gas separator 145 a part ofthe pretreater efiluent flows through conduit 215 under control of valve216 to conduit 144 to separator 145 by-passing cooler 143. Thepretreater efiluent flows from cooler 14 3 through conduit 144 toliquid-gas separator 1 15.

In liquid-gas separator 145 the hydrocarbons boiling below the boilingrange of reformer feed together with hydrogen and some hydrogen sulfideseparate from hydrocarbons boiling in the boiling range of reformer feedand that amount of hydrogen sulfide soluble in the condensedhydrocarbons at the existing temperature and pressure. The hydrocarbonsboiling below the boiling range of reformer feed, i.e., lighthydrocarbons together with the hydrogen and hydrogen sulfide flow aspretreater gas from separator 145 through conduit 132 and thence in partor wholly as described hereinbefore under control of valve 133 throughbranch 146 under control of valve 217 and conduit 132 to pretreaterabsorber as described hereinbefore.

The condensed hydrocarbons boiling in the boiling range of reformer feedand usually having a maximum boiling point at a temperature within therange of about 350 to about 420 F. flow from liquid-gas separator 114-5through pipe 147 to the suction side of pump 148.

Pump 148 discharges the condensed pretreater effluent, i.e.,hydrocarbons having a maximum boiling point at a tempetrature Within therange of about 350 to about 420 F. into pipe through which the condensedpretreater efiluent flows to heat exchanger 156. In heat exchanger 15%the condensed pretreater effluent is in indirect heat exchange relationwith the bottoms of splitter 153 flowing from splitter 153 through pipe164. From heat exchanger 151) the condensed pretreater effluent flowsthrough pipe 151 to heat exchanger 1411 where the condensed preheaterefiluent is in indirect heat exchange relation with pretreater efliuentas described hereinbefore. In heat exchanger 14% the condensedpretreater efi luent is heated to a temperature at which hydrogen,hydrogen sulfide, and hydrocarbons boiling below reformer feed range arevolatile. From heat exchanger 1 3%) the partially condensed pretreaterefduent flows through pipe 152 to splitter 15?).

In splitter 153 hydrocarbons boiling below the boiling point at 180 to250 F. end point naphtha or any other desired cut and lighterhydrocarbon together with hydrogen and hydrogen sulfide dissolved in thecondensed pretreater effluent at the temperature and pressure existingin separator 145 are taken overhead through conduit 154 to cooler 155.In cooler 155 C and heavier hydrocarbons are condensed. The condensedand uncondensed splitter overhead fiows from cooler 155 through conduit156 to accumulator 157. (In place of the splitter type of separation astripper type of separation employing stripping gas can be used).

In accumulator 157 the uncondensed splitter overhead is vented throughconduit 15$ to the refinery fuel main. The condensed splitter overheadflows from accumulator 157 to the debutanizer or light straight-runnaphtha stabilizer through pipe 159 under control of valve 161. Aportion of the condensed splitter overhead is diverted through pipe 16%to the suction side of pump 1612. Pump 162 discharges the divertedportion of the condensed splitter overhead into pipe 163 along which thecondensed splitter overhead fiows to splitter 153 for use as reflux.

The bottoms of splitter 153, i.e., hydrocarbons boiling in the boilingrange of reformer feed and usually having a maximum boiling point withinthe range of about 350 and 420 F. fiows from splitter 153 through pipe164 to heat exchanger 1511 where the bottoms is in indirect heatexchange relation with the condensed pretreater cffiuent as describedhereinbefore. The splitter bottoms, i.e., reformer feed having a maximumboiling point within the range of about 358 and about 420 F. andcontaining not more than 1 ppm. of nitrogen flows from heat exchanger1511 through pipe 165 to the suction side of pump 11%.

Pump 1.66 discharges the reformer feed into conduit 167 at a pressuregreater than that in reformer 173. The reformer feed containing not morethan 1 p.p.m. of nitrogen fiows through conduit 167 to heat exchanger163 where the reformer feed is in indirect heat exchange relation withthe final reformer efiiuent flowing from reformer 183 through conduit184. At some point in conduit 167 up-stream of heat exchanger 168hydrogen-containing reformer recycle gas in the proportion set forthhereinbefore flowing rom compressor 131 through conduit 192 at apressure at least equal to that in conduit 167 is mixed with thereformer feed to provide a reformer charge mixture.

From heat exchanger 168 the reformer charge mixture flows throughconduit 169 to coil 170 in heater 171. In heater 171 the reformer chargemixture is heated to a reforming temperature dependent upon the activityof the platinum-group reforming catalyst, the required octane rating ofthe reformate and other factors known to those skilled in the art andbeing no part of the present invention.

From heater 171 the charge mixture flows through conduit 172; toreformer 173. In reformer 173 the charge mixture contacts platinum-groupparticle-form reforming catalyst. The effluent from reformer 1'73designated first effluent flows from reformer 1'73 through conduit 174to coil 175 in heater 176. in heater 1'76 the first efiluent is heatedto a reforming temperature the same as, higher or lower than that towhich the charge mixture is heated.

From heater 176 the re-heated first efiluent flows through conduit 177to reformer 178. In reformer 178 the re-heated first effiuent contactsplatinum-group particleform reforming catalyst. The effluent fromreformer 178 designated second effluent flows from reformer 178 throughconduit 179 to coil 1% in heater 131.

In heater 131 the second effluent is re-heated to a reformingtemperature the same as, higher or lower than the temperatures to whichthe reformer charge mixture and the first effluent are heated. Fromheater 181 the re-heated second efiluent flows through conduit 132 toreformer 133.

In reformer 1% the re-heated second effluent contacts platinum-groupparticle-form reforming catalyst. The efduent from reformer 133,designated final effluent, flows from reformer 133 through conduit 1ndto heat exchanger 163. In heat exchanger 168 the final eifluent is inindirect heat exchange relation with the reformer charge mixture asdescribed hereinbefore.

From heat exchanger 163 the final efiiuent flows through conduit 185 tocooler 186. In cooler 186 the final efiluent is cooled to a temperatureat which 0.; and heavier hydrocarbons are condensed. The condensed anduncondensed final effluent flows from cooler 1 56 through conduit 137 toreformer liquid-gas separator 188.

In separator the uncondensed final effluent separates from the condensedfinal efiluent. The uncondensed final effluent, designated reformerrecycle and excess gas, flows from separator 188 through conduit 189.Excess re- [former gas, designated reformer cascade gas, flows throughconduit 218 under control of valve 219 to the pretreating unit asdescribed hereinbefore. Reformer recycle gas in an amount to provide thehydrogen to reformer feed mol ratio set forth hereinbefore flows fromconduit 189 through conduit 190 to the suction side of compressor 191.Compressor 191 recompresses the reformer recycle gas to a pressurehigher than that in reformer 73. The recompressed reformer recycle gasflows through conduit 192 to conduit 167 as described hereinbefore.

The condensed final effiuent flows from separator 188 through pipe 193to heat exchanger 194. The condensed final effiuent, designated finalcondensate, is in indirect heat exchange relation with the bottoms offractionator 196 flowing thereto through pipe 212. In heat exchanger 194the final condensate is heated to a temperature at which C and lighterhydrocarbons are volatile. From heat exchanger 194 the heated finalcondensate flows through pipe 195 to fractionator 196.

In fractionator 196 C and lighter hydrocarbons are taken as overheadthrough pipe 197 to cooler 198. In cooler 198 the overhead is cooled toa temperature at which C and heavier hydrocarbons are partiallycondensed. From cooler 198 the uncondensed and condensed overhead flowsthrough pipe 199 to accumulator 200.

In accumulator 200 uncondensed hydrocarbons lighter than C are separatedfrom condensed C and heavier hycarbons. The uncondensed overhead flowsfrom accumulater 200 through pipe 201 to the refinery fuel main. Thecondensed overhead flows from accumulator 200 through pipe 202 undercontrol of valve 203 to means for recovering C and C hydrocarbons. Aportion of the condensed overhead is diverted through pipe 204 to thesuction side of pump 205. Pump 205 discharges the diverted portion ofcondensed overhead into pipe 206 through which the condensed overheadflows to [fractionator 196 for use as reflux.

A portion of the bottoms of fractionator 196 flows from fractionator 196through pipe 207 to the suction'side of pump 208. Pump 208 dischargesthat portion of the fractionator bottoms into pipe 209 through which thefractionator bottoms flow to heat exchanger 210.

In heat exchanger 210 the fractionator bottoms is heated to atemperature at which the lighter hydrocarbons are volatile. From heatexchanger 210 the heated fractionator bot-toms flows through pipe 211 tofractionator 196. Any other means for maintaining the requiredtemperature in fractionator 196 can replace the reboiler described.

The bottoms of fractionator 195, designated reformate and usuallycomprising C and heavier hydrocarbons usually having a maximum boilingpoint within the range of about 350 to about 420 F. flows fromfractionator 196 through pipe 212 to heat exchanger 194. In heatexchanger 194 the reformate is in indirect heat exchange relation withfinal condensate as described hereinbefore. From heat exchanger 194 thereformate flows through pipe 213 to cooler 214. In cooler 214 thereformate is cooled to a temperature at which the lowest boilingcomponent of the reformate is liquid. The cooled reformate flows fromcooler 214 through pipe 221 to means (not shown) for removing residualhydrogen sulfide, such as a caustic wash employing an aqueous sodiumhydroxide solution having a density of to 35, preferably 20 Baum andthence to means for adding additives, e.g., tetraethyl lead, etc., tostorage and/ or distribution.

The following are illustrative reaction conditions for hydrogenation andhydrodesulfurization of a petroleum fraction boiling above the boilingrange of reformer feed and usually having an initial boiling point abovea temperature within the range of about 350 to about 420 F e.g.-,domestic heating oil in conjunction with at least 1'8 partialhydrodecontamination of high nitrogen content naphtha as definedhereinbefore:

Hydrotreater Catalyst: about 1.53.8 wt. percent cobalt oxide; about 7-16wt. percent molybdenum oxide Carrier: alumina Broad Preferred Reactionpressure, p.s.i.g 200 to 1,000 390 to 850 Reaction temperature, 550 to850 700 to 800 Space velocity, v./v./hr. 2 to 10 4 to G Hydrogen/barrelof mixed feed, sci. 200 to 2,000 320 to 1,000 Mols hydro en/moihydrocrabon .4 to 3.8 .8 to 2.7 Hydrogen Partial Pressure, p.s.i.a.- 120to 900 125 to 570 Illustrative of the hydrodecontarnination of a blendof autobenous naphtha, i.e., naphtha boiling within the range 100 F. to420 F. obtained from the first unit with low nitrogen content naphtha asdefined hereinbefore, such as straight-run naphtha are the following:

Pretrealer Catalyst: about 1.5 to 3.8 wt. percent cobalt oxide; about 7to 16 Wt. percent molybdenum oxide Carrier: alumina Broad PreferredReaction pressure, p.s.i.g 100 to 1,000 400 to 500 Reaction temperature,F. 600 to 850 675 to 725 S ace velocity, V./V./hr 1 to 10 2.5 to 5Hydrogen/bbl. of charge, s.e. 350 to 2,500 400 to 800 Illustrative ofthe conditions under which the hydrodecontaminated blend of highnitrogen naphtha and straight-run naphtha is reformed are the following:

As an example of the conjunct treatment of a high nitrogen naphtha andan unstable domestic fuel oil to produce an at least partiallydesulfurized and denitrogenized naphtha suitable for blending with astraight-run naphtha to be desulfurized and denitrogenized to provide areformer feed containing not more than about 1 ppm. of nitrogen and adomestic fuel oil stable with respect to color and sediment afterstorage at 100 F. for twelve Weeks, and reforming the naphtha blend overa platinum catalyst are the flows of liquids and gases illustrated inFIGURES la and b.

An unstable domestic fuel oil, i.e., a petroleum fraction boiling abovethe boiling range of reformer feed, having a 10 percent point of 454 F.,a percent point of 589 F. and an end point of 641 F. is drawn from asource not shown through pipe 1 by pump 2. Pump 2 discharges theunstable domestic heating oil into pipe 3 at a pressure greater than thepressure in refining reactor 33. The unstable domestic heating oil flowsthrough pipe 3 to pipe 4. A high nitrogen content naphtha, as definedhereinbefore, such as a coker naphtha is drawn from a source not shownthrough pipe 222 by pump 223. Pump 223 discharges the coker naphtha intopipe 224 (at a pressure in excess of the pressure in refining reactor33) through which the coker naphtha flows to pipe 4. In pipe 4- theunstable domestic heating oil and coker naphtha are mixed in theproportions of about 1 to about volumes of coker naphtha to 100 volumesof unstable domestic heating oil, e.g., about 17 volumes of unstableheating oil to about volumes of coker naphtha. The mixture of unstabledomestic heating oil and coker naphtha flows in part through pipe 5 tothe top of absorber 15 and the balance through pipe 7 wholly or in partto heat exchanger 9 and thence through pipe 12 to absorber 15 or whollyor in part through pipe 10 under control of valve 11 to pipe 12. Thedistribution of the mixture of unstable domestic heating oil and cokernaphtha between'pipes 5 and 7 is dependent upon the temperature requiredin the upper and lower portions of the absorber. That is to say, theflow of hydrocarbon oil, i.e., unstable domestic heating oil and cokernaphtha and the flow of gases through conduits 86 and 58 to absorber 15are balanced to remove substantially all of the C and heavierhydrocarbons from the gases and to remove water and heat exchangerdeposit precursors from the hydrocarbon oil. The distribution of themixture of unstable domestic heating oil and coker naphtha between pipes8 and 10 is dependent upon maintaining the maximum temperature inabsorber 15 at which substantial absorption of C and heavierhydrocarbons by the oil and stripping of water, oxygen and depositprecursors by the gases occurs. Usually a temperature of about 100 toabout 150 F. is satisfactory in absorber 15.

The stripped gases and absorbed water, oxygen, etc. are vented fromabsorber 15 through conduit 16 to the refinery fuel main. Thehydrocarbon oil containing absorbed C and heavier hydrocarbons flowsfrom absorber 15 through pipe 17 to the suction side of pump 18.

Pump 18 discharges the mixture of unstable domestic heating oil andcoker naphtha into pipe 19. The mixture flows through pipe 19 to heatexchanger 20 Where the mixture of unstable domestic heating oil andcoker gasoline is in indirect heat exchange relation with theuncondensed vapors flowing from the high temperature flash drum 37through conduit 39. From heat exchanger 20 the mixture of unstabledomestic heating oil and coker naphtha flows through pipe 21 to heatexchanger 22 where the mixture is in indirect heat exchange relationwith the bottoms of the light product stripper flowing through pipe 109.The mixture of unstable domestic heating oil and coker naphtha flowsthrough pipe 23 to heat exchanger 24 where the unstable mixture is inindirect heat exchange relation with the uncondensed vapors flowing fromhigh temperature flash drum 37 through conduit 38. From heat exchanger24 the unstable mixture of domestic heating oil and coker naphtha, i.e.,refiner feed mixture, flows through pipe 25 to heat exchanger 26. Inheat exchanger 26 the refiner feed mixture is in indirect heat exchangerelation with the eflluent of hydrotreater or refiner 33 flowing throughconduit 35. A portion or all of the refiner feed mixture can flow aroundheat exchanger 26 through pipe 27 under control of valve 28 to maintaina temperature in high temperature flash drum 37 required to maintain thespecified flash point for the bottoms. From heat exchanger 26 therefiner feed mixture flows through pipe 29 to coil 30 in heater 31.

In heater 31 the refiner feed mixture is heated to a temperature suchthat when mixed with hydrogencontaining gas to form a refiner chargemixture, the refiner charge mixture is at a reaction temperature withinthe limits set forth hereinbefore for the treatment of a petroleumfraction boiling above the boiling range of reformer feed, say about 650to about 725 F. The heated mixture flows from heater 31 through pipe 32to hydrotreater 33.

Hydrogen-containing gas flowing at about 850 p.s.i.g. from heatexchanger 63 through conduit 34 is introduced into the hydrotreater orrefiner 33 at the rate of about 1000 toabout 1500 standard cubic feet(s.c.f.) of hydrogen per barrel of the refiner feed mixture.

In hydrotreater or refiner 33 the refiner feed mixture is contacted witha catalyst having the capabilities of hydrodesulfurization, broadlyhydrodecontaminating, and

hydrogenating hydrocarbon fractions at the temperatures and pressuresemployed. Presently preferred is the aforedescribed mixture of oxides ofcobalt and molybdenum supported on alumina.

The efiiuent from hydrotreater or refiner 33 comprising hydrogensulfide, ammonia, hydrogen, and C and heavier hydrocarbons flows throughconduit 35 to heat exchanger 26 where the hydrotreater effluent is inindirect heat exchange relation with the relatively cold refiner feedmixture as described hereinbeforel From heat exchanger 26 thehydrotreater elfluent flows through conduit 36 to high temperature flashdrum 37.

In high temperature flash drum 37 a temperature is maintained at whichunder the existing pressure the bottoms thereof have the specified endpoint. Usually the temperature in high temperature flash drum 37 isabout' 24 the uncondensed refining reactor effluent flows throughconduit 39 to heat exchanger 20 where the uncondensed refining reactoreflluent is in indirect heat exchange relation with the refiner feedmixture as described hereinbefore. From heat exchanger 20- theuncondensed hydrotreater effluent flows through conduit 40 to cooler orcondenser 41 where the temperature of the uncondensed refining reactorefifiuent is lowered to a practical limit. Usually the pressure is about740 p.s.i.g. and a temperature of about 70 to about 90 F. is maintained.From condenser 41 the cooled uncondensed hydrotreater effluent flowsthrough conduit 42 to low temperature flash drum 43.

In low temperature flash drum 43 the hydrocarbons of the condensedportion of the refining reactor efliuent are separated from thehydrogen, C to C hydrocarbons, hydrogen sulfide and ammonia. The lowtemperature flash drum overhead comprising principally hydrogen, C to Chydrocarbons, hydrogen sulfide, and ammonia flows from flash drum 43through conduit 44 to high pressure means for absorbing hydrogen sulfide45. Presently it is preferred to use diethano-lamine as the absorbentfor hydrogen sulfide. The low temperature flash drum overhead flowsupwardly through absorber 45 countercurrent to the downwardly flowingdiethanolamine (DEA). The low temperature flash drum overhead strippedof hydrogen sulfide flows fromscrubber 45 through conduit 54 toknock-out pot 55 where entrained DEA (if any) is dropped-out and thencethrough conduit 57 to compressor 60. ,A portion of the overhead from thelow temperature flash drum flowing through conduit 57 and in excess ofthe amount of hydrogen to be recycled to hydrotreater 33 is divertedthrough conduit 58 under control of valve 59 to absorber 15 where any Cand heavier hydrocarbons are stripped from the low temperature flashdrum overhead. Any entrained DEA is removed from knock-out pot 55through conduit 56.

Returning to low temperature flash drum 43 and following the fiow of theliquid phase separated therein, it will be manifest that the bottoms ofthe low temperature flash drum 43 comprising the aforesaid hydrocarbonsflow therefrom through pipe 68 to heat exchanger 69 where the lowtemperature flash drum bottoms is in indirect heat exchange relationwith at least a portion of the bottoms of the light products stripperflowing through pipe 107. From heat exchanger 69 the low temperatureflash drum bottoms flows through pipe 70 to pipe 71 where the lowtemperature flash drum bottoms is mixed with the overhead from the heavyproducts stripper flowing through pipe 74.

Returning to high temperature flash drum 37 the flow of the condensedhydrotreater effluent will be followed. The condensed hydrotreateretlluent comprising treated domestic heating oil flows from hightemperature flash drum 37 through pipe 72 to heavy products stripper 73.In heavy products stripper '73 the treated domestic heating oil is steamstripped of hydrocarbons boiling in the boiling range of reformer feed,designated naphtha, and the naphtha taken as an overhead through pipe74. The overhead from the heavy products stripper flows through pipe 74to pipe 71 where the overhead from the heavy products stripper is mixedwith the bottoms of the low temperature flash drum 43. The bottoms fromthe heavy products stripper 73 flows through pipe 76 to the bottom oflight products stripper 75.

In light products stripper 75 the mixture of heavy products stripperoverhead and low temperature flash drum bottoms is fractionated orstripped with steam to provide an overhead comprising components boilingin the boiling range of reformer feed and a bottoms comprisinghydrocarbons having a percent point not lower than about 370 F. andpreferably not lower than about 420 F., i.e., treated domestic heatingoil and meeting the desired flash point. The light products stripperbottoms flows therefrom through pipe 105 to the suction side of pump106. Pump 1G6 discharges the light prod ucts stripper bottoms into pipe107 through which the bottoms flow to heat exchanger 69. Dependent uponthe temperature of the low temperature flash drum condensate leavingheat exchanger 69 all or a portion of the light products stripperbottoms is diverted to pipe 225 under control of valve 226 to bypassheat exchanger 69. The light products stripper bottoms then flowsthrough pipe 108 to heat exchange 63 where the bottoms is in indirectheat exchange relation with hydrogen-containing gas flowing at apressure in excess of that in hydrotreater 33 from compressor '60through conduit 62. From heat exchanger 63 the bottoms flows throughpipe 169 to heat exchanger 22 where the bottoms is in indirect heatexchange relation with the refiner feed mixture flowing to thehydrotreater through pipe 21. From heat exchanger 22 the light productsstripper bottoms flows through pipe 233 to heat exchanger 9 where thebottoms is in indirect heat exchange relation with the refiner feedmixture flowing to the hydrotreater as described hereinbcfore. From heatexchanger 9 the light products stripper bottoms flows through pipe 234to cooler 227 where the temperature of the bottoms is reduced to about140 F. or lower. From cooler 227 the bottoms flows through pipe 228alternatively to a caustic wash (not shown) to remove residual sulfurcompounds soluble in aqueous caustic, if any, and/or means to removeWater and then to storage, etc., or to storage, admixing of additives,distribution, etc., to provide domestic heating oil stable to color andsediment.

Returning to light products stripper 75, the flow of the components ofthe feed to light products stripper '75 which boil in the boiling rangeof reformer feed or lower will be traced. The overhead from the lightproducts stripper comprises residual amounts of hydrogen, hydrogensulfide, and C and heavier hydrocarbons boiling in the boiling range ofreformer feed and usually having a maximum boiling point within therange of about 350 to about 420 F. The overhead flows from lightproducts stripper 75 through conduit 77 to cooler 73 Where the C andheavier hydrocarbons are condensed. From the cooler 78 the condensed anduncondensed overhead flows through conduit 79 to accumulator 86. Inaccumulator St? the uncondensed overhead comprising hydrogen, hydrogensulfide, and C to C hydrocarbons is separated from the condensedoverhead and flows through pipe 82 to low pressure means for removinghydrogen sulfide 83. Presently, it is preferred to use diethanolamine asthe absorbent for hydrogen sulfide. In absorber 83 the uncondensedoverhead flows upwardly counter-current to the downwardly flowingdiethanolamine. The stripped uncondensed overhead flows from absorber 83through 2.2 conduit 86 to absorber 15 where the stripped uncondensedoverhead is contacted with the feed to the hydrotreater 33 as describedhereinbefore.

The condensed overhead from light products stripper 75 flows fromaccumulator through pipe 87 to heat exchanger 229. A portion, to serveas reflux in light products stripper 75, is drawn by pump throughconduit 88 under control of valve 89 and discharged into pipe 91. Thedischarge from pump 90 flows through pipe 91 to light products stripper75 for use as reflux. The corn densed overhead flowing through pipe 87is heated in heat exchanger 229 to a temperature at which C and lighterhydrocarbons are volatile. From heater 229* the heated condensedstripper overhead flows through pipe 230 to reformer feed fractionator92. Alternatively, the condensed overhead flows directly fromaccumulator 80 to pump 103.

Fractionator 92 can be operated to provide a pretreater naphtha blendcomponent as a bottoms comprising a sub-. stantially dehexanized, or asubstantially depentanized, or a substantially debu-tanized or asubstantially depropanized pretreater naphtha blend component boiling inthe boiling range of reformer feed and usually having a maximum boilingpoint within the range of about 350 to about 420 F.

In fractionator 92 the C or C or C or C and lighter hydrocarbons aretaken as overhead through pipe 93. The overhead is cooled in cooler 94to a temperature at which hydrocarbons heavier than C or heavier than Cor heavier than 0.; or heavier than C are condensed dependent uponwhether a dehexanized or a depentanized or a debutanized or adepropanized pretreater naphtha blend component is required or, in otherwords, hydrocarbons boiling in the range of the required reformer feedare condensed. The condensed and uncondensed fractionator overhead flowfrom cooler 94 through conduit 95 to accumulator 96. The uncondensedoverhead flows from accumulator 96 through conduit 101 to means forrecovering the valuable hydrocarbons.

The condensed fractionator overhead boiling predominantly below theboiling range of the pretreater naphtha blend component flows fromaccumulator 96 through pipe 97 to recovery of the C to C hydrocarbonsthe presence of which is dependent upon the split made in fractionator92. A portion suflicient for use as reflux in fiactionator 92 isdiverted by means of conduit 98 under control of a valve not shown tothe suction side of pump 99. Pump 99 discharges the reflux portion ofthe condensed overhead into pipe 1%. The reflux portion of the condensedoverhead flows through pipe 100 to fractionator 9.2.

The bottoms of fractionator 92 is the pretreater naphtha blend componentand comprises the autogenous reformer feed produced in the hydrotreateror refiner 33 and the partially treated high nitrogen content naphthawhich formed a portion of the refiner feed mixture. The bottoms boil inthe boiling range of reformer feed and usually have a maximum boilingpoint within. the range of about 350 to about 420 F. The bottoms flowsfrom fractionator 92 through pipe 102 to the suction side of pump 103.Pump 103 discharges the bottoms, i.e., pretreater naphtha blendcomponent into pipe 104 through which the pretreater naphtha blendcomponent flows to pipe 242 (FIG. 1b) where the pretreater naphtha blendcomponent is mixed with a low nitrogen naphtha (as de-' finedhereinbefore) to provide the pretreater feed mixture.

A low nitrogen content naphtha (as defined hereinbefore) capable ofbeing reformed, such as straight-run naphtha, is drawn from a source notshown through pipe 244) by pump 241 and discharged into pipe 242. Thelow nitrogen content naphtha, hereinafter designated straight-rungasoline, is mixed in pipe 242 with the aforesaid pretreater naphthablend component flowing from the refining section through pipe 104 andP-ltM to form a pretreater blend the nitrogen content of which can bereduced in existing reformer feed preparation facilities to not morethan 1 ppm. of nitrogen. The blend flows through pipe 242 and branch 243under control of valve 244 to absorber 110. Hydrogen-containing gasflowing from pretreater liquid-gas separator 145 through conduit 132under control of valve 133 and through branch conduit 146 under controlof valve 217 to absorber 11 1 contacts the pretreater blend therein. Theflow of pretreater blend through pipes 242 and 243 and the How of gasthrough conduit 132 and branch conduit 146 are proportioned so that theC and heavier hydrocarbons in the hydrogen-containing gases aresubstantially completely removed by the naphtha blend withoutsubstantial absorption of hydrogen sulfide while water, oxygen andexchange deposit precursors are stripped from the pretreater blend withthe hydrogen-containing gases.

The hydrogen-containing gases stripped of C and heavier hydrocarbonsflow from absorber 111 through conduit 113. Gas in excess of thatrequired in hydrotreater or refiner 33 (FIG. 1a) is diverted throughconduit 113 under control of valve 114 to the refinery fuel main. Thebalance and usually major portion, i.e., the pretreater cascade gasflows through conduit P-245 (FIG. 1b) to conduit H-245 (FIG. la) andthence either to conduit 62 (hydrotreater pressure less than pretreaterpressure) through conduits 61 and 71 or to the suction side ofcompressor 66 (hydrotreater pressure greater than pretreater pressure).The pretreater blend flows from absorber 111) through pipe 246 to thesuction side of pump 247. .The pretreater blend the nitrogen content ofwhich can be reduced in existing reformer feed preparation facilities tonot more than 1 p.p.m of nitrogen is discharged by pump 247 at apressure greater than that in pretreater 131 into pipe 248. Thepretreater blend flows through pipe 248 to heat exchanger 249 where thepretreater blend is in indirect heat exchange relation with the effluentfrom pretreater 131 flowing through conduit 141. From heat exchanger 249the pretreater blend flows through pipe 120 to heat exchanger 121 wherethe pretreater blend is in indirect heat exchange relation with theefiiuent of pretreater 131 flowing through conduit 138. From heatexchanger 121 the pretreater blend flows through pipe 122 to coil 123 inheater 124.

in heater 124 the pretreater blend is heated to a temperature at which,when mixed with hydrogen-containing gas under the pressure existing andin the presence of hydrogen and a desulfurizing, denitrogenizing andhydrogenating catalyst, the naphtha blend is hydrodecontaminated toprovide a reformer feed containing not more than about 1 p.p.m. ofnitrogen. Temperatures within the limits set forth hereinbefore forhydrodecontamination with a mixture of oxides of cobalt and molybdenumare illustrative. The heated pretreater blend flows from heater 124through pipe 125 to pretreater 131. Hydrogencontaining gas, i.e.,reformer cascade gas, flowing from the reforming unit through conduits189 and 218 under control of valve 220 or from compressor 129 throughconduit 130 is mixed with the heated pretreater blend within the rangeof proportions set forth hereinbefore for hydrodecontamination of thepretreater blend. The

mixture of pretreater blend and hydrogen-containing gases flowsdownwardly through pretreater 131.

The effiuent of pretreater 131 flows therefrom through conduit 138 toheat exchanger 121 where the pretreater effluent is in indirect heatexchange relation with the pretreater blend as described hereinbefore.The pretreater efiluent flows from heat exchanger 1.21 through conduit139 to heat exchanger 14% where the pretreater efiluent is in indirectheat exchange relation with the condensate from liquid-gas separator 145flowing from pump 148 and exchanger 150 through pipe 151. From heatexchanger 140 the pretreater effluent flows through conduit 141 to heatexchanger 249 where the pretreater effiuent is in indirect heat exchangerelation With the pretreater blend as described hereinbefore. From heatexchanger 249 the pretreater efi luent flows through conduit 142 tocooler or condenser 143 where the temperature of the pretreater effiuentis lowered to that at which under the existing pressure a major portionof the C and substantially all of the heavier hydrocarbons arecondensed. From condenser 143 the cooled pretreater efiluent flowsthrough conduit 144 to liquid-gas separator 145. A portion or all of thepretreater effiuent can by-pass condenser 143 to avoid over-cooling thepretreater eflluent. Thus, a portion of the pretreater efliuent can flowfrom conduit 142 through conduit 215 under control of valve 216 toconduit 144.

in liquid-gas separator 145 a minor portion of the C and substantiallyall of the lighter hydrocarbons together with hydrogen, hydrogen sulfideand ammonia are separated from the condensed C and heavier hydrocarbons.The overhead gas flows from separator 145 through conduit 132 undercontrol of valve 133 to absorber as described hereinbefore. When theamount of reformer cascade gas is insufficient to meet the needs ofpretreater 131 a portion of the pretreater gas is diverted throughconduit 134 under control of valve to the suction side of compressor136. The repressured pretreater gas is discharged through conduit 137into conduit 125 and mixed therein with the heated pretreater blend.

The condensed C and heavier hydrocarbons together with small amounts ofhydrogen derivatives of contaminants, hereinafter designated pretreatercondensate, flows from separator through pipe 147 to the suction side ofpump 148. Pump 148 discharges into pipe 149 through which the pretreatercondensate flows to heat exchanger 15%. In heat exchanger 15% thepretreater condensate is in indirect heat exchange relation with thebottoms of splitter 153 flowing through pipe 164. From heat exchanger150 the pretreater condensate flows through pipe 151 to heat exchanger140 where the pretreater condensate is in indirect heat exchangerelation with the pretreater effluent flowing from pretreater 131 andheat exchanger 121 through conduit 139 as described hereinbefore. Fromheat exchanger 14 .1 the pretreater condensate flows through pipe 152 tosplitter 153.

In splitter 153, which is provided with a reboiler or other means formaintaining a temperature at which a substantially dehexanized or asubstantially depentanized, or a substantially debutanized, or asubstantially depropanized reformer feed is prepared, the overheadcomprising respectively C or C or C or C and lighter hydrocarbons,hydrogen, and hydrogen derivatives of contaminants is taken throughconduit 154.

The overhead flows through conduit 154 to cooler 155 where C or C or Cor C and heavier hydrocarbons are condensed. The condensed anduncondensed overhead flows from cooler 155 through conduit 156 toaccumulator 157.

The uncondensed hydrocarbons, hydrogen, and hydrogen derivatives ofcontaminants flow from accumulator 157 through conduit 158 to therefinery fuel main. The condensed hydrocarbons flow from accumulator 157through pipe 159 under control of valve 161 to recovery of condensedhydrocarbons. A portion of the condensed hydrocarbons is divertedthrough pipe to the suction side of pump 162. Pump 162 discharges thediverted condensed overhead into pipe 163 through which the condensedhydrocarbons flow to fractionator 153 for use as reflux.

The splitter bottoms flows through pipe 164 to heat exchanger 150 andthence through pipe 165 to the suction side of pump 166. Pump 166discharges the split ter bottoms, now designated reformer feedcontaining not more than 1 p.p.m. of nitrogen into pipe 167. Thereformer feed flows through pipe 167 to heat exchanger 168 where thebottoms is in indirect heat exchange relation with the final etfiuent ofthe reforming section. The bottoms contains not more than 1 p.p.m. ofnitrogen. The bottoms is the hydrocarbon feed to the reforming unit.

Before describing the flow of liquids and gases through the reformingunit the flow of gases through the pre treating unit and the refiningunit will be summarized. Hydrogen-containing gas produced in thereformer unit in excess of that required for reforming, designatedreformer cascade gas, flows from liquid-ga separator 188 through conduit189 to conduit 218 in the reforming unit under control of valve 219 atsubstantially the pres sure in reforming reactor 183 less line pressuredrop to conduit 218 and from conduit 218 to conduit 125 and pretreater131 under control of valve 220 When pre treater pressure is less thanreformer pressure. The re former cascade gas flows through conduit 127(valve 220 closed; valve 128 open) to the suction side of compressor"129 when pretreater pressure is greater than reformer pressure.Compressor 129 discharges the recompressed reformer cascade gas at apressure greater than pre treater pressure into conduit 130.Hydrogen-containing gas, pretreater gas from separator 145 flows toabsorber 118. From absorber 118 a portion of the pretreater gas,designated pretreater cascade gas, flows through conduits P445 and H245and 61 to conduit 67 (pretreater pressure greater than refiner pressure)or through conduits 1 -245, 11-245 and 64 to the suction side ofcompressor 66. Compressor 66 discharges the pretreater cascade gas intoconduit 67 at a pressure higher than that of the hydrotreater 33. Thehydrogen-containing gas from low temperature flash drum 43 (FIGURE 1a)flows through high pressure DEA absorber 45 to knockout pot and thencethrough conduit 57 to compressor 60. Thus, the hydrogen-containing gasin excess of that required for reforming is used to pretreat a naphthablend and then is used to refine a mixture of the petroleum fractionboiling above the boiling range of reformer feed and high nitrogencontent naphtha.

The flow of liquids and gases in the removal of hydrogen sulfide in thehigh pressure and low pressure diethanolamine scrubbers is substantiallyas described hereinbefore.

The reformer feed containing not more than 1 p.p.m. of nitrogen flowsthrough pipe (FIGURE 1c) to the suction side of pump 166. Pump 166discharges the reformer feed into conduit 167 at a pressure greater thanthe pressure in reformer 173 (FIGURE 1b). At some point in conduit 167intermediate to pump 166 and to heat exchanger 168 hydrogen-containinggas discharged at a pressure at least equal to that in reformer 173 bycompressor 191 flows through conduit 192 into conduit 167. Thehydrogen-containing gas is mixed with the naphtha blend in conduit 167in the proportions set forth hereinbefore. The mixture ofhydrogen-containing gas and reformer feed, hereinafter designatedreformer charge mixture, flows through conduit 167 to heat exchanger168. In heat exchanger 168 the reformer charge mixture is in indirectheat exchange relation with the effluent from reformer 183 (finaleffluent) flowing thereto through conduit 184. From heat exchanger 168the reformer charge mixture flows conduit 169 to coil 170 in furnace171. In coil 170 the reformer charge mixture is heated to a reformingreaction temperature within the limits set forth hereinbefore. Theheated reformer charge mixture flows from coil 170 through conduit172.to reformer 173. The effluent of reformer 173, hereinafterdesignated first reformer effluent, flows through conduit 17 1 to coilin furnace 176. In coil 175 the first reformer eflluent is reheated to areforming temperature equal to, lower than, or higher than the inlettemperature of reformer R From coil 175 the reheated first reformereffluent flows through conduit 177 to the second reformer 178. From thesecond reformer 178 the second reformer eifiuent flows through conduit179 to coil 188 in furnace 181. In coil 180 the second reformer effluentis reheated to reforming temperature within the range set forthhereinbefore and equal to, higher than or lower than the vapor inlettemperatures of reactors R and R From coil 180 the reheated secondreformer effluent flows through conduit 182 to third re'- former 183.The effluent of third reformer 183, i.e., final effluent, flowstherefrom through conduit 184 to heat exchanger 168 where the finalefliuent is in indirect heat exchange relation with the reformer feed asdescribed hereinbefore. From heat exchanger 168 the final efliuent flowsthrough conduit 185 to cooler 186. In cooler 186 the final effluent iscooled to a temperature at which under the existing pressure C andheavier hydrocarbons are condensed. The uncondensed portion and thecondensed portion of the final effiuent flow from cooler 186 throughconduit 187 to liquid-gas separator 188.

In liquid-gas separator 188 the uncondensed portion of the finaleffluent separates from the condensed portion of the final efiiuent. Theuncondensed portion of the final efiluent comprising hydrogen and C to Chydrocarbons and designated reformer recycle gas hereinafter flows fromseparator 188 through conduit 189.. At some point in conduit 189 aportion of the reformer recycle gas about equal to the gas made in thereformers is diverted through conduit 218 under control of valve 219 tothe pretreating unit. The diverted portion of the reformer gas,designated reformer cascade gas, flows through conruit 218 to pretreater131 as described hereinbefore. The balance is reformer recycle gas whichflows through conduit 198 to the suction side of compressor 191.Compressor 191 discharges the recycle gas into conduit 192 through whichthe recycle gas flows to conduit 167 to mix with the reformer feed toform the reformer charge mixture as previously described.

The condensed portion of the final eflluent, hereinafter designatedcondensate, is separated from the recycle gas in separator 188 and flowstherefrom through pipe 193 to heat exchanger 194 where the condensate isin indirect heat exchange relation with the bottoms of fractionator 196flowing therefrom through pipe 212. From heat ex.- changer 194 thecondensate flows through pipe 195 to fractionator 196.

In fractionator 196 a temperature is maintained at which C and lighterhydrocarbons are volatile. The C and lighter hydrocarbons are takenoverhead from fractionator 196 through pipe 197. The overhead fromfractionator 196 flows through pipe 197 to cooler 198 where the overheadis cooled to a temperature at which C and C hydro carbons are condensed.The cooled overhead flows through pipe 199 to separator 208'. Inseparator 200 the uncondensed overhead is separated from the condensedoverhead and is vented to the refinery fuel main through pipe 201. Thecondensed overhead flows from accumu lator 200 through pipe 282 undercontrol of valve 203 to C and C recovery. A portion of the condensedover.- head sufficient to serve as reflux in fractionator 196 isdiverted from pipe 202 through pipe 284 to the suction side of pump 285.Pump 285- discharges the reflux into pipe 286 through which the refluxflows to fractionator 196.

Bottoms from fractionator 196, i.e., C and heavier hydrocarbons flowthrough a reboiler comprising pipe 207, pump 288, pipe 209, heatexchanger 21!), and pipe 211 or any other suitable means for maintaininga temperature in fractionator 196 at which C and lighter hydrocarbonsare volatile. The net bottoms product from fractionator 196, i.e., theraw reformate yield, flows from fractionator 196 through pipe 212 toheat exchanger 194 where the bottoms is in indirect heat exchangerelation with the condensate from separator 188 as describedhereinbefore. From heat exchanger 194, the bottoms flows through pipe213 to cooler 214 where the bottoms is cooled to a temperature at whichthe lowest boiling hydrocarbon is a liquid. From cooler 214 thereformate, C and heavier hydrocarbons, flows through pipe 221 to means(not shown) for removing residual hydrogen sulfide, such as a causticWash employing an aqueous sodium hydroxide solution having a density of5 to 35, preferably 20 to 2? 25 Baum and thence to means for theaddition of additives, blending, storage and distribution.

I claim:

1. In the method of upgrading a hydrocarbon mixture boiling above theboiling range of reformer feed and below the boiling range oflubricating oil, designated hydrotreater feed, and obtaining ahydrocarbon mixture boiling above the boiling range or reformer feed andbelow the boiling range of lubricating oil and having substantiallylower concentrations of sulfur and nitrogen than said hydrotreater feed,designated hydrotreater product, and upgrading reformer feed containingmore than 1 p.p.m. of nitrogen and obtaining reformer feed containingnot more than 1 p.p.m. of nitrogen wherein the aforesaid hydrotreaterfeed is contacted with a static bed of sulfur and nitrogen-insensitiveparticle-form solid hydrogenating catalyst having hydrodesulfurizing andhydrodenitrogenizing capabilities in a hydrotreater at hydrotreaterhydrodecontaminating conditions of pressure in the range of 200 to 1000p.s.i.g., temperature in the range of 550 to 850 F., liquid hourly spacevelocity in the range of 2 to 10, and hydrogen-to-hydrotreater feed molratio in the range of 0.4 to 3.8; wherein a hydrotreater efiiuentcomprising hydrogen, hydrogen sulfide, ammonia, and C and heavierhydrocarbons is obtained; wherein said hydrotreater eflluent isseparated into hydrotreater gas comprising hydrogen, hydrogen sulfide,ammonia, and C to C hydrocarbons, autogenous reformer feed having anitrogen concentration greater than 1 p.p.m., and comprising C andheavier hydrocarbons having an end boiling point in the range of about350 to about 420 F., d.- signated pretreater blend stock, and upgradedhydrocarbon mixture being the aforesaid hydrotreater product havingconcentrations of sulfur and nitrogen substantially lower than those ofsaid hydrotreater feed; wherein said hydrotreater gas is vented; whereinsaid pretreater blend stock is admixed with extraneous reformer feedhaving a lower concentration of nitrogen in proportion to form a blendedpretreater feed having a nitrogen content reducible to not more than 1p.p.m. in the aforesaid pretreater at pretreater hydrodecontaminatingconditions set forth hereinafter to provide blended pretreater feed;wherein said blended pretreater feed is contacted with a static bed ofparticle-form solid sulfurand nitrogen-insensitive hydrogenatingcatalyst having hydrodesulfurizing and hydrodenitrogenizing capabilitiesunder pretreater hydrodecontaminating conditions of pressure in therange of 100 to 1000 p.s.i.g., temperature in the range of 600 to 850F., liquid hourly space velocity in the range of 1 to 10, and hydrogencirculation in the range of 350 to 2500 s.c.f. of hydrogen per barrel ofsaid blended pretreater feed; wherein pretreater effluent comprisinghydrogen sulfide, ammonia, hydrogen, and C and heavier hydrocarbons isobtained; wherein said pretreater effluent is separated into pretreatergas comprising hydrogen sulfide, ammonia, hydrogen, and C to Chydrocarbons, an intermediate fraction comprising C hydrocarbons, andreformer feed comprising C and heavier hydrocarbons containing not morethan 1 p.p.m. of nitrogen; wherein suflicient of said pretreater gasflows to said hydrotreater to supply the aforesaid 0.4 to 3.8 mols ofhydrogen per mol of hydrotreater feed; wherein said reformer feed iscontacted in a reformer with a static bed of nitrogen-sensitiveparticleform solid platinum-group metal reforming catalyst at reformingconditions of pressure in the range of 100 to 1000 p.s.i.g., temperaturein the range of 800 to 1000 F., liquid hourly space velocity in therange of 0.5 to 10, and hydrogen-to-reformer feed mol ratio in the rangeof 4 to 20; wherein a reformer efliuent comprising hydrogen and C andheavier hydrocarbons is obtained; wherein said reformer eflluent isseparated into reformer gas comprising hydrogen and C to C hydrocarbons,and raw reformate comprising C and heavier hydrocarbons; wherein saidreformer gas is separated into reformer recycle gas and reformermake-gas; wherein said reformer recycle gas flows to said reformer tomaintain the aforesaid hydrogen-toreformer feed mol ratio; and whereinsaid reformer makegas flows to said pretreater to maintain the aforesaidhydrogen circulation in the range of 350 to 2500 s.c.f. of hydrogen perbarrel of blended pretreater feed; the improvement which comprisesmixing the aforesaid hydrotreater feed with high nitrogen contenthydrocarbon mixture in the proportion of about volumes of hydrotreaterfeed per 1 to 100 volumes of high nitrogen content hydrocarbon mixtureto form novel hydrotreater feed, said high nitrogen content hydrocarbonmixture boiling in the boiling range ofreformer feed and having a higherconcentration of nitrogen than can be reduced to not more than 1 p.p.m.in the aforesaid pretreater at the aforedescribed pretreaterhydrodecontamim ating conditions, even when mixed with the aforesaidextraneous reformer feed; contacting the aforesaid novel hydrotreaterfeed in the aforesaid hydrotreater with the aforesaid particle-formsolid sulfurand nitrogen-insensitive hydrogenating catalyst at theaforesaid hydrotreater hydrodecontaminating conditions; obtaininghydrotreater effluent comprising hydrogen sulfide, ammonia, hydrogen,and C and heavier hydrocarbons; separating said hydrotreater eflluentinto hydrotreater gas comprising hydrogen sulfide, ammonia, hydrogen,and C to C hydrocarbons, pretreater blend stock consisting of autogenousreformer feed and partially hydrodenitrogenized high nitrogen contenthydrocarbon mixture, said pretreater blend stock comprising C andheavier hydrocarbons having an end boiling point in the range of about350 to about 420 F., and having a higher concentration of nitrogen thancan be reduced to more than 1 p.p.m. in the aforesaid pretreater at theaforesaid pretreater hydrodecontaminating conditions, and the aforesaidupgraded hydrotreater product; treating a major portion of saidhydrotreater gas to remove hydrogen sulfide; and recycling at least aportion of the so-treated hydrotreater gas to the aforesaidhydrotreater.

2. The method set forth in claim 1 wherein the aforesaid hydrocarbonsfraction boiling above the boiling range of reformer feed and below theboiling range of lubricating oil is raw domestic fuel oil, wherein thehydrotreater product has a ten percent point in the range of 370 to 420F., and wherein the hydrotreater product is washed with aqueous caustic,the caustic-washed hydrotreater product is water-washed, and stabilizeddomestic fuel oil is obtained, said domestic fuel oil being stable to atleast one of color and sediment, containing not more than 1 to 2 percenttotal sulfur, and not more than 1 to 2 percent of the mercaptan-sulfuroriginally present in the aforesaid raw domestic fuel oil.

References Cited in the file of this patent UNITED STATES PATENTS2,691,623 Hartley Oct. 12, 1954 2,773,008 Hengstebeck Dec. 4, 19562,800,428 Hengstebeck July 23, 1957 2,834,718 Stanford et al. May 13,1958 2,910,426 Gluesenkamp et al. Oct. 27, 1959 2,937,134 Bowles May 17,1960

1. IN THE METHOD OF UPGRADING A HYDROCARBON MIXTURE BOILING ABOVE THEBOILING RANGE OF REFORMER FEED AND BELOW THE BOILING RANGE OFLUBRICATING OIL, DESIGNATED HYDROTREATER FEED, AND OBTAINING AHYDROCARBON MIXTURE BOILING ABOVE THE BOILING RANGE OR REFORMER FEED ANDBELOW THE BOILING RANGE OF LUBRICATING OIL AND HAVING SUBSTANTIALLYLOWER CONCENTRATIONS OF SULFUR AND NITROGEN THAN SAID HYDROTREATER FEED,DESIGNATED HYDROTREATER PRODUCT, AND UPGRADING REFORMER FEED CONTAININGMORE THAN 1 P.P.M. OF NITROGEN AND OBTAINING REFORMER FEED CONTAININGNOT MORE THAN 1 P.P.M. OF NITROGEN WHEREIN THE AFORESAID HYDROTREATERFEED IS CONTACTED WITH A STATIC BED OF SULFURAND NITROGEN-INSENSITIVEPARTICLE-FORM SOLID HYDROGENATING CATALYST HAVING HYDRODESULFURIZING ANDHYDROGENITROGENIZING CAPABILITIES IN A HYDROTREATER AT HYDROTREATERHYDRODECONTAMINATING CONDITIONS OF PRESSURE IN THE RANGE OF 200 TO 1000P.S.I.G., TEMPERATURE IN THE RANGE OF 550* TO 850*F., LIQUID HOURLYSPACE VELOCITY IN THE RANGE OF 2 TO 10, AND HYDROGEN-TO-HYDROTREATERFEED MOL RATIO IN THE RANGE OF 0.4 TO 3.8; WHEREIN A HYDROTREATEREFFLUENT COMPRISING HYDROGEN, HYDROGEN SULFIDE, AMMONIA, AND C1 ANDHEAVIER HYDROCARBONS IS OBTAINED; WHEREIN SAID HYDROTREATER EFFUENT ISSEPARATED INTO HYDROTREATER GAS COMPRISING HYDROGEN, HYDROGEN SULFIDE,AMMONIA, AND C1 TO C3 HYDROCARBONS, AUTOGENOUS REFORMER FEED HAVING ANITROGEN CONCENTRATION GREATER THAN 1 P.P.M., AND COMPRISING C4 ANDHEAVIER HYDROCARBONS HAVING AN END BOILING POINT IN THE RANGE OF ABOUT350* TO ABOUT 420*F., DESIGNATED PRETREATER BLEND STOCK, AND UPGRADEDHYDROCARBON MIXTURE BEING THE AFORESAID HYDROTREATER PRODUCT HAVINGCONCENTRATIONS OF SULFUR AND NITROGEN SUBSTANTIALLY LOWER THAN THOSE OFSAID HYDROTREATER FEED; WHEREIN SAID HYDROTREATER GAS IS VENTED; WHEREINSAID PRETREATER BLEND STOCK IS ADMIXED WITH EXTRANEOUS REFORMER FEEDHAVING A LOWER CONCENTRATION OF NITROGEN IN PROPORTION TO FORM A BLENDEDPRETREATER FEED HAVING A NITROGEN CONTENT REDUCIBLE TO NOT MORE THAN 1P.P.M. IN THE AFORESAID PRETREATER AT PRETREATER HYDRODECONTAMINATINGCONDITIONS SET FORTH HEREINAFTER TO PROVIDE BLENDED PRETREATER FEED;WHEREIN SAID BLENDED PRETREATER FEED IS CONTACTED WITH A STATIC BED OFPARTICLE-FORM SOLID SULFUR-AND NITROGEN-INSENSITIVE HYDROGENATINGCATALYST HAVING HYDRODESULFURIZING AND HYDRODENITROGENIZING CAPABILITIESUNDER PRETREATER HYDRODECONTAMINATING CONDITIONS OF PRESSURE IN THERANGE OF 100 TO 1000 P.S.I.G., TEMPERATURE IN THE RANGE OF 600* TO850*F., LIQUID HOURLY SPACE VELOCITY IN THE RANGE OF 1 TO 10, ANDHYDROGEN CIRCULATION IN THE RANGE OF 350 TO 2500 S.C.F. OF HYDROGEN PERBARREL OF SAID BLENDED PRETREATER FEED; WHEREIN PRETREATER EFFUENTCOMPRISING HYDROGEN SULFIDE, AMMONIA, HYDROGEN, AND C1 AND HEAVIERHYDROCARBONS IS OBTAINED; WHEREIN SAID PRETREATER EFFUENT IS SEPARATEDINTO PRETREATER GAS COMPRISING HYDROGEN SULFIDE, AMMONIA, HYDROGEN, ANDC1 TO C3 HYDROCARBONS, AN INTERMEDIATE FRACTION COMPRISING C4HYDROCARBONS, AND REFORMER FEED COMPRISING C5 AND HEAVIER HYDROCARBONSCONTAINING NOT MORE THAN 1 P.P.M. OF NITROGEN; WHEREIN SUFFICIENT OFSAID PRETREATER GAS FLOWS TO SAID HYDROTREATER TO SUPPLY THE AFORESAID0.4 TO 3.8 MOLS OF HYDROGEN PER MOL OF HYDROTREATER FEED; WHEREIN SAIDREFORMER FEED IS CONTACTED IN A REFORMER WITH A STATIC BED OFNITROGEN-SENSITIVE PARTICLEFORM SOLID PLATINUM-GROUP METAL REFORMINGCATALYST AT REFORMING CONDITIONS OF PRESSURE IN THE RANGE OF 100 TO 1000P.S.I.G., TEMPERATURE IN THE RANGE OF 800* TO 1000*F., LIQUID HOURLYSPACE VELOCITY IN THE RANGE OF 0.5 TO 10, AND HYDROGEN-TO-REFORMER FEEDMOL RATIO IN THE RANGE OF 4 TO 20; WHEREIN A REFORMER EFFUENT COMPRISINGHYDROGEN AND C1 AND HEAVIER HYDROCARBONS IS OBTAINED; WHEREIN SAIDREFORMER EFFUENT IS SEPARATED INTO REFORMER GAS COMPRISING HYDROGEN ANDC1 TO C3 HYDROCARBONS, AND RAW REFORMATE COMPRISING C4 AND HEAVIERHYDROCARBONS, WHEREIN SAID REFORMER FAS IS SEPARATED INTO REFORMERRECYCLE GAS FLOWS FORMER MAKE-GAS; WHEREIN SAID REFORMER RECYCLE GASFLOWS TO SAID REFORMER TO MAINTAIN THE AFORESAID HYDROGEN-TOREFORMERFEED MOL RATIO; AND WHEREIN SAID REFORMER MAKEGAS FLOWS TO SAIDPRETREATER TO MAINTAIN THE AFORESAID HYDROGEN CIRCULATION IN THE RANGEOF 350 TO 2500 S.C.F. OF HYDROGEN PER BARREL OF BLENDED PRETREATER FEED;THE IMPROVEMENT WHICH COMPRISES MIXING THE AFORESAID HYDROTREATER FEEDWITH HIGH NITROGEN CONTENT HYDROCARBON MIXTURE IN THE PROPORTION OFABOUT 100 VOLUMES OF HYDROTREATER FEED PER 1 TO 100 VOLUMES OF HIGHNITROGEN CONTENT HYDROCARBON MIXTURE TO FORM NOVEL HYDROTREATER FEED,SAID HIGH NITROGEN CONTENT HYDROCARBON MIXTURE BOILING IN THE BOILINGRANGE OF REFORMER FEED AND HAVING A HIGHER CONCENTRATION OF NITROGENTHAN CAN BE REDUCED TO NOT MORE THAN 1 P.P.M. IN THE AFORESAIDPRETREATER AT THE AFOREDESCRIBED PRETREATER HYDRODECONTAMINATINGCONDITIONS, EVEN WHEN MIXED WITH THE AFORESAID NOVEL TRANEOUS REFORMERFEED; CONTACTING THE AFORESAID NOVEL HYDROTREATER FEED IN THE AFORESAIDHYDROTREATER WITH THE AFORESAID PARTICLE-FORM SOLID SULFUR- ANDNITROGEN-INSENSITIVE HYDROGENATING CATALYST AT THE AFORESAIDHYDROTREATER HYDRODECONTAMINATING CONDITIONS; OBTAINING HYDROTREATEREFFUENT COMPRISING HYDROGEN SULFIDE, AMMONIA, HYDROGEN, AND C1 ANDHEAVIER HYDROCARBONS; SEPARATING SAID HYDROTREATER EFFLUENT INTOHYDROTREATER GAS COMPRISING HYDROGEN SULFIDE, AMMONIA, HYDROGEN, AND C1TO C3 HYDROCARBONS, PRETREATER BLEND STOCK CONSISTING OF AUTOGENOUSREFORMER FEED AND PARTIALLY HYDRODENITROGENIZED HIGH NITROGEN CONTENTHYDROCARBON MIXTURE, SAID PRETREATER BLEND STOCK COMPRISING C4 ANDHEAVIER HYDROCARBONS HAVING AN END BOILING POINT IN THE RANGE OF ABOUT350* TO ABOUT 420*F., AND HAVING A HIGHER CONCENTRATION OF NITROGEN THANCAN BE REDUCED TO MORE THAN 1 P.P.M. IN THE AFORESAID PRETREATER AT THEAFORESAID PRETREATER HYDRODECONTAMINATING CONDITIONS, AND THE AFORESAIDUPGRADED HYDROTREATER PRODUCT; TREATING A MAJOR PORTION OF SAIDHYDROTREATER GAS TO REMOVE HYDROGEN SULFIDE; AND RECYCLING AT LEAST APORTION OF THE SO-TREATED HYDROTREATER GAS TO THE AFORESAIDHYDROTREATER.